New base special 28 august 2014

Copyright © 2014 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced,
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NewBase 28 August 2014 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Pakistan Drilling for Shale Likely to Begin in Pakistan Next Year
The Express Tribune + NewBase
Federal Minister for Petroleum and Natural Resources Shahid Khaqan Abbasi announced Monday
that the government is working on a shale gas policy framework and drilling for this yet-to-be-
explored energy source will start next year, The Express Tribune newspaper reported.
The minister said that some energy companies were interested in venturing into the exploration of
shale gas. He was speaking at the signing of an exploration licence and petroleum concession
agreement for the Karak North block with Tallahassee Resources in Islamabad. Earlier this year
the newspaper had reported that Zaver Petroleum Corporation, an oil and gas exploration firm and
a part of Pakistan’s Hashoo Group is eyeing investment in country’s oil and gas sector, especially
shale gas.
In January, Eni and Pakistan discussed the need of enhancing country’s gas production by
exploiting shale gas. Pakistan has been facing severe energy shortage for last few years and is
trying to source natural gas from various sources. It has been in discussion with Qatar to import
LNG. Pakistan is also working to get gas from Iran through the proposed Iran-Pakistan pipeline
project, which at the moment is stuck due to US sanctions on Tehran, although Iran has
completed the section of pipeline that lies on its soil. In January, Eni and Pakistan discussed the
need of enhancing country’s gas production by exploiting shale gas.

Oman Gov asks PDO to raise oil production to 600,000bpd
TMES OF OMAN + NEWBASE
Oman government has asked the majority state-owned Petroleum Development Oman (PDO) to
raise its crude production to 600,000 barrels per day
(bpd), from its long-term plateau of 500,000-550,000bpd
annual production set by the company more than three
years ago.
The growth in crude production will be achieved by
applying state-of-the-art drilling technology and focusing
on boosting output from several small areas and with sour
gas injection, Salim Nasser Said Al Aufi,
undersecretary at the Ministry of Oil and Gas, told journalists on the sidelines of launching the
Oil and Gas Year Oman 2014 energy report.
"We, from the government, put a challenge to PDO trying to understand what would it take for the
company to increase its production up to 600,000bpd. We need to understand the time-frame,
cost, it is not going to be cheap and dominated by a lot of drilling activities," Al Aufi said, adding
that PDO's production has been growing slightly and this year, the company is producing 570,000
bpd so far .
However, he noted that the company is not discovering major fields. "It is still more of traditional
exploration activities,
probably in areas where PDO
did not pay too much
attention. Al Aufi said the
country's oil production target
is set at 950,000 bpd and so
far the average production is
945,000 bpd. "Now we have a
mix of several companies that
compensate each other.
The undersecretary pointed
out that with the new drilling
technology, PDO will be able
to drill wells faster. "We can
steer drilling in thin oil wells.
In the past, we were able to
stay steady in a thing oil well.
New fracking techniques have also been developed outside Oman. We need to adopt that
expertise locally as well as services associated with it.
Referring to the growing cost of average oil production, Al Aufi said the cost of production using
enhanced oil recovery technique is high. Enhanced oil recovery fields constitute 14-15 per cent of
total oil production in the country and this will go up to 30 per in the next ten years, which will jack
up the cost for bringing crude oil above the ground.
"Our challenge is to keep the cost of oil production at the present level and offset inflation and
cost escalation. He also said that the government is watching the recent fluctuation in the
international market for crude oil prices and will prepare next year's budget accordingly.

Philippines: Nido Petroleum Report on Galoc reserves and activities
Source: Nido Petroleum
Highlights:
• Strong production performance since Phase II start-up in December 2013 to 31 July 2014 of over 2.0
MMbbls (gross); 1.8MMbbls since 1 January 2014 (gross).
• Independent reserves assessment by GCA at 31 July 2014, estimates Galoc oil field 1P Developed Reserves at
9.2 MMstb on a gross basis (1.8MMbbls on a net entitlement to Nido basis).
• 2P and 3P Developed Reserves are estimated at 11.9MMstb and 15.6MMstb respectively on a gross basis
(2.3MMstb and 3.1MMstb on a net entitlement to Nido basis).
• Field expansion studies being considered by the SC 14C1 Operator.
• Decision of further drilling activities expected in late 2014 or early 2015.
• Nido has a 22.88% working interest in SC 14C1 and the Galoc oil field.
Nido Petroleum has
provided an update
regarding the Galoc oil
field in SC 14 C1, Republic
of the Philippines:
Production Performance
Production performance
from Galoc field has
remained strong since start-
up of Phase II in December
2013. The field has
produced in excess of 2
MMbbls (gross) in the first
eight months of Phase II
production to end July
2014. Production between 1
January and 31 July 2014
has been 1.8 MMbbls
(gross). Nido expects a total of ten (10) cargos will be delivered from the field during 2014, with the seven
cargos already sold this year going to local South East Asian refineries.
Further Expansion Studies
During the year, Galoc field Operator Otto Energy has progressed technical studies which have provided a
greater understanding of the Galoc main field area (currently being developed with four wells) and the
exploration potential recognised in the Galoc Mid and Galoc North Areas.
Although no firm proposals are under consideration by the SC 14 C1 Joint Venture at this time,the Operator
considers that the results of the current technical studies may lead to furtheractivities to unlock the upside
potential of the Galoc Mid Area and/or to undertake additionaldrilling and infill activities to complement
existing productions at the Central Field Area.

GCA Reserves Update
GCA has completed an Independent Reserves Update of the Galoc field as at 31 July 2014 in accordance
with the SPE/WPC/AAPG/SPEE Petroleum Resource System (SPE PRMS) Definitions and Guidelines and
the ASX Listing Rules including recently implemented Listing Rules 5.25 to 5.44 where applicable.
The updated assessment was prepared using deterministic methods and is based on an updated decline
analysis of field production history to 31 July 2014 from the Phase 1 and Phase II development wells.
Production performance since the year-end 2013 Reserves assessment has been on trend with Gaffney,
Cline and Associates 1P forecast as at 31 December 2013. The 2P and 3P estimated ultimate recoveries at
31 July 2014 are approximately 2% and 4% lower than the previous estimates, respectively. These
differences, after accounting for recent production, are within acceptable uncertainty limits for reserves
estimation and are not considered a material change.
The Galoc Phase 1 wells Galoc-3ST1 and Galoc-4 continue to perform close to previous forecasts. As at 31
July 2014, Galoc-4 was producing at an oil rate of 2,560 stbd (approx. 32% of field rate); cumulative
production from the well was 10.3 million barrels (MMstb).
The Galoc Phase II wells Galoc-5 and Galoc-6 have made a significant contribution to the field production
since the successful commissioning of Galoc Phase II in December 2013. As at 31 July 2014, they were
producing at a combined oil rate of 4,680 stbd (approx. 58% of field rate); cumulative production from the
two wells was 1.3 MMstb.
The reserves position for the Galoc Oil Field as at 31 July 2014 is as follows:
Notes:
1. Net Entitlement Reserves are Nido’s net economic entitlement under the Service Contract that governs the
asset, i.e. Company’s share of cost oil and profit oil.
2. No account has been taken of any losses for fuel or shrinkage.
3. The reference point for the purpose of measuring and assessing the estimated oil reserves is at the metering
point on the FPSO.
4. No oil produced from the Galoc field is used as fuel.
Nido’s Galoc Reserves have been assessed on a net entitlement basis through an Economic Limit Test
which incorporates the applicable SC 14C1 fiscal terms. Table 2 compares GCA’s Independent Reserves
assessment for the Galoc oil field at 31 July 2014
with the Reserves position at 31 December 2013,
on a gross (100%) field basis.

Nigeria: Shell sells Nigeria oil fields
Source: Reuters + NewBase
Royal Dutch Shell has sold some of four oil fields up for grabs in Nigeria, it said on Wednesday, as the
oil and gas company pushes ahead with global asset sales to cut costs. Shell last year put up for sale its
30 percent shares in four oil blocks in the Niger Delta -- Oil Mining Licence (OML) 18, 24, 25, 29 -- as
well as a key pipeline, the Nembe Creek Trunk Line.
'We have signed sales & purchase agreements for some of the Oil Mining Leases, but not all that we are
seeking to divest,' a Shell spokesman said. No details were available on the value of the deals signed, nor
when the full process will be completed.
France's Total and Italy's Eni are also set to raise revenue from the sale of their 10 percent and 5 percent
shares in the assets. The Nigerian National Petroleum Corporation (NNPC) owns the remaining 55
percent. The Financial Times on Wednesday reported that Shell is close to selling the assets for about $5
billion to domestic buyers. In March, Reuters reported that Nigerian firms Taleveras and Aiteo made the
highest bid of $2.85 billion for the biggest of the four oil fields, OML 29.
Shell, along with many other oil majors, is undergoing a broad process of asset sales across the world in an
effort to cut costs and boost profits. Other companies, including Total, Eni, Chevron and ConocoPhillips
have sought to pull out of the oil-rich West African country which has been plagued by oil theft.

U.S. liquid fuels production growth more than offsets unplanned supply
disruptions. Source: U.S. Energy Information Administration,
Record-setting liquid fuels production growth in the United States has more than offset the rise in unplanned
global supply disruptions over the past few years, although differences in quality and location suggest that
the substitution may not be exactly 1-for-1. U.S. liquid fuels production, which includes crude oil,
hydrocarbon gas liquids, biofuels, and refinery processing gain, grew by more than 4.0 million barrels per
day (bbl/d) from January 2011 to July 2014, of which 3.0 million bbl/d was crude oil production growth.
During that same period, global unplanned supply disruptions grew by 2.8 million bbl/d.
U.S. production growth, the main factor counterbalancing the supply disruptions on the global oil market,
has contributed to a decrease in crude oil price volatility since 2011. Over the past 13 months, the monthly
average Brent price has moved within a narrow $5 per barrel range, between $107 per barrel and $112 per
barrel. In contrast, the range of monthly average Brent prices over the prior 13-month period (June 2012-
June 2013) was $21 per barrel.
Global unplanned supply disruptions averaged 3.2 million bbl/d during the first seven months of 2014 and
peaked at 3.5 million bb/d in May 2014. The current level of supply disruptions is the highest since the Iraq-
Kuwait War (1990-91), when supply disruptions peaked at 4.3 million bbl/d, based on data from the
International Energy Agency

DNV GL’s map shows risks of offshore activities in the Arctic
Source DNV GL
The world’s need for energy is driving interest in further industrial activity in the Arctic, yet
the region’s conditions are highly variable depending on the type of activity, location and time
of year. This creates a complex risk picture, DNV GL writes.
DNV GL has therefore developed an interactive Arctic Risk Map to present the risks associated with
offshore and maritime activities in the Arctic. The map aims to provide stakeholders with a comprehensive
tool for decision-making and transparent communications, DNV GL has explained.
“The Arctic is not a monolithic area and the risk picture varies accordingly. Stakeholders therefore need a
sound decision basis for understanding the risks associated with Arctic development and transportation.
The DNV GL Arctic Risk Map can help facilitate transparent discussions to address the many dilemmas
related to activity in the region,” says Børre Paaske, project manager at DNV GL – Oil & Gas.
The map presents multiple dimensions, such as the seasonal distribution of ice, metocean (physical
environment) conditions, sea-ice concentrations, biological assets, shipping traffic and oil and gas resources,
in a user-friendly, single layout. It also includes a Safety and Operability Index, showing the variation in
different factors that impact the risk level depending on the season and their location in the Arctic.
In addition, a location- and season-specific index has been developed showing the environmental
vulnerability of marine resources with respect to oil spill as an external stressor. In general, DNV GL’s
analysis shows that the Arctic environment is characterised by seasonal variations in vulnerability, and that
this vulnerability increases in the summer months along with the level of industrial activity.
However, this differs greatly between regions. Some areas, for example, are particularly vulnerable in
winter, when they are used by birds for wintering or as spawning grounds for fish.
Severe consequences
DNV GL says that as a result, the consequences of an accident in the Arctic would likely be more severe in
some areas than others. The map is a useful tool to identify regions that require special attention when it
comes to planning activities and for imposing mitigation measures throughout the year. The map can also

provide input to decisions-makers about restricting certain types of activities in specific areas at different
times of the year.
“The risk level in the Arctic must be equivalent to – or better than – the best performance in the industry
today. The Arctic’s varied and complex conditions require the industry to take a stepwise approach in which
learning and technology are developed progressively regarding the more challenging Arctic areas,” says
Elisabeth Tørstad, CEO of Oil & Gas, DNV GL.
“As an independent body, DNV GL takes an active role in ensuring that any increase in industrial activity
has a strong focus on safeguarding life, property and the environment. This Arctic Risk Map is a great
example of our vision in action,” she adds.

World’s existing power plants on track to pour 300b tons
of carbon dioxide into atmosphere . Saudi Gazette + NewBase
The drive to meet the world’s ever-growing energy demand means that global power sector
commitments – the projected lifetime carbon emissions of currently working power plants – have
not declined in a single year since 1950. These so-called committed emissions are growing at
about 4 percent a year, according to the study, and in 2012 reached 307 billion tons of carbon
dioxide, a new study from Princeton University and the University of California-Irvine published
Aug. 26 in the journal Environmental Research Letters revealed.
The world’s existing power plants are on track to pour more than 300 billion tons of carbon dioxide
into the atmosphere, and current monitoring standards often fail to take these long-term emissions
into account, the new research by scientists at UC Irvine and Princeton University noted. The
paper is the first to estimate the lifetime carbon emissions of power plants globally over multiple
years.
The study comes as the United States is attempting for the first time to regulate emissions from
existing power plants, a proposal the Environmental Protection Agency (EPA) announced several
weeks ago and aims to finalize by next June.
The researchers suggest that current United Nations accounting methods, which chart annual
carbon dioxide discharge, should also tally the projected lifetime emissions of power plants to

provide a more accurate picture of their impact on global warming. “International efforts all center
on what we emit every year, but that misses the point,” said Steven Davis, an earth system
scientist at the University of California, Irvine, and the study’s co-author. “We have information
about what is coming in the future.” Davis wrote the paper with Robert Socolow of Princeton,
known for his theory that a series of environmental steps that cut greenhouse gas, which he called
wedges, could together flatline carbon emissions.
The study reflects international trends in investment in coal-burning power plants, with
construction of coal-fired power plants slowing in the West since the 1980s but increasing in
China, India, and other areas of the developing world.
“There is a global effort to reduce carbon dioxide, but it is actually increasing at a shocking rate,”
Davis said. “When you build a power plant, it is going to stick around for 40 to 50 years and emit a
lot of CO2.”
In 2012, China’s power sector represented 42 percent of worldwide committed emissions, 98
percent of which were tied to coal, the authors found. Plants in the United States and Europe
together accounted for 20 percent. That share of lifetime carbon emissions has declined in the
United States since the late 1980s, in part due to the shift from coal-burning power plants to plants
fueled by natural gas, but also because the power infrastructure is not expanding. Levels
remained steady in Europe.

The study found that lifetime emissions from China’s power plants have experienced a less rapid
increase since the country’s 2006 peak. Although China continues to build power plants, they are
not being built as rapidly as in the recent past, Davis said.
However, China is “passing the torch” to other industrializing countries—including Indonesia,
Russia, Saudi Arabia, and Iran—which are ramping up their power sectors, often by building new
coal plants. The study presents a bleak look at international efforts to prevent global warming
while it questions the accounting used to tally emissions to meet climate treaties.
The authors found that lifetime carbon emissions from currently operating power plants represent
a substantial portion of what is allowed for in climate models to prevent global temperatures from
warming more than 2 degrees Celsius from the preindustrial era—the current international target.
The emissions from existing power plants in China and the United States, for example, represent
53 and 21 percent, respectively, of each nation’s carbon budget to meet its carbon target from all
sources, according to the study.
In the paper, Robert Socolow, a Princeton professor, emeritus, of mechanical and aerospace
engineering, and co-author Steven Davis, a professor of earth system science at the UC-Irvine,
develop a “commitment accounting” that assigns all the future emissions of a facility to the year
when it begins working. This method reveals that the fossil-fuel-burning power plants built
worldwide in 2012 alone will produce roughly 19 billion tons of the global-warming gas carbon
dioxide (CO2) over their lifetime, assuming the plants operate for 40 years. This is considerably
more than the 14 billion tons of CO2 emissions produced by all the plants operating worldwide in
2012.
“We are flying a plane that is missing a crucial dial on the instrument panel,” Socolow said. “The
needed dial would report committed emissions. Right now, as far as emissions are concerned, the
only dial on our plane tells us about current emissions, not the emissions that current capital
investments will bring about in future years.”
Further findings from the study show that the plants that were operating around the world in 2012,
before they are shut down, will emit more than 300 billion tons of CO2. The number of new power
plants is rapidly growing and very few old ones are being retired. In fact, total remaining
commitments in the global power sector have not declined in a single year since 1950. These
commitments grew at an average rate of 4 percent per year between 2000 and 2012.
The authors said the increases in global commitments reflect the rapid expansion of China’s
power sector since 1995, as well as new power plants built in developing countries such as India,
Indonesia, Saudi Arabia and Iran. Plants in China and India now respectively represent 42 percent
and 8 percent of committed future emissions, while plants operating in the United States and
Europe represent roughly 11 percent and 9 percent, respectively.
The share of commitments related to natural gas-fired plants has increased from roughly 15
percent in 1980 to 27 percent in 2012, but aside from the Middle East, almost the entire
developing world is relying on coal its industrialization.
“A high-carbon future is being locked in by the world’s capital investments in power plants and
other infrastructure,” Socolow said. “Finding paths to low-carbon industrialization must become a
global priority.”

NewBase Special Report Covering Mozambique Key
Projects and Business Highlights 2014
Mozambique appears as one of the most promising country for natural gas exploration production and could
become one of the largest exporter of liquefied natural gas (LNG) under the lead of companies such as
Anadarko Petroleum Company (Anadarko) from USA, Eni from Italy, Mitsui E&P from Japan, China
national Petroleum Corporation (CNPC or PetroChina), Kogas from South Korea, Galp Energia from
Portugal, BPRL and Emprecia Nacional de Hidrocarbonetos ENH from Mozambique.
Since Mozambique is not willing to depend exclusively from the natural gas exploration and production, it
initiated projects on the downstream side with companies such as Royal Dutch Shell (Shell) from Europe
and Sasol from South Africa to monetize locally the resources with projects such as Gas-To-Liquid.
Benchmarking Brazil and Nigeria, Mozambique is attentive to maximize the local added value.
In this perspective Mozambique is working on its new regulation regarding the local content to be
considered by the companies to develop all the upstream, midstream and downstream projects,
This regulation generate intense discussion between the local authorities and the companies putting on hold
final investment decisions in the meantime to know what shall be the final contractual obligations.
Anyway all the companies are taking this temporary period to explore all the scenario to explore these giant
and unexpected resources in the optimized way combining onshore LNG train and floating LNG solutions.
1- Gas-To-Liquid projects to queue behind LNG Plants
The Royal Dutch Shell (Shell) on one side and the tandem Sasol-Eni on another side signed these last
weeks agreement with the national oil company (NOC) Empresa Nacional de Hidrocarbonetos (ENH) to
start feasibility studies on Gas-To-liquid (GTL) projects in Mozambique.
During the last two years Mozambique emerged as one of the potential key players of the natural
gas market with the discoveries performed in the Rovuma Basin, offshore Mozambique on the east of
coast of Africa.

Pioneered by Anadarko on the Area 1 and Eni on the Area 4, the Rovuma basin exploration has proven to
be one of the most prolific opportunity in the world for non-associated gas over the last ten years.
Although Anadarko and Eni have not completed yet the evaluation of the reserves in their respective Area,
their estimations of recoverable reserves in the Rovuma Basin fluctuate between 70 trillion and 100 trillion
cubic feet (tcf).
With these gigantic reserves, the Mozambique
Government required Anadarko and Eni to align on
onshore development in order to optimize the
infrastructures required to support the production
and exportation of liquefied natural gas (LNG)
while both operators will develop the offshore part
of their projects in the Area 1 and Area 4 on their
own. At this stage Anadarko and Eni consider
conventional concept, based on offshore platform
and export pipeline to shore, as well as floating
LNG vessels.
Anyway in both cases, exporting LNG from
Mozambique will face tougher competition in
coming years because of similar export projects in
Tanzania, Australia, Russia and North America.
After the spiraling costs experiences in Australia, all
the companies such as Anadarko, Shell or Eni are assessing carefully all multi-$billion LNG projects and
investigate solutions to mitigate risks. Mozambique GTL projects to leverage LNG projects
Among the solutions, the conversion of natural gas into liquids has proven to be pertinent in a context of
wide spread between the low gas prices and the high crude oil prices. From the evidences accumulated these
last years, this wide spread between energy prices appears sustainable enough to consider GTL projects in
Mozambique.
In Mozambique these GTL projects would
provide all parties with solid benefits for all
parties. For the Government, the Mozambique
GTL projects should reduce the import of
expensive crude oil for the distribution of
transportation fuels. Through ENH they should
also increase the local monetization of the
Rovuma Basin resources.
For the companies such as Shell, Sasol,
Anadarko and Eni, the integration of
GTL projects in the development of large non-
associated gas projects will leverage their
added value while mitigating reliance on
gas markets. Because of their experience in
world-scale GTL projects in Africa, Asia and Middle-East, Shell and Sasol appear as the best partners for
Eni and ENH to develop these Mozambique GTL projects.

In starting feasibility studies now, the Shell GTL and Sasol GTL projects in Mozambique with ENH and
Eni should run into commercial operations by 2021 – 2022.
2- Eni strategy in good progress with Area-4 FLNG projects
The Italian national oil company (NOC) Eni is currently proceeding to the pre-qualification of the
engineering companies and shipyards to be invited to bid (ITB) for the front end engineering and design
(FEED) of the first floating liquefied natural gas (FLNG) vessel to be moored in the Area-4 in the Strait of
Mozambique on the East Coast of Africa.
Together with the Texas-based Anadarko Petroleum Corporation (Anadarko), Eni is leading the
development of the huge reserves of gas discovered these last five years in the Rovuma Basin offshore
Mozambique and Tanzania. Anadarko is leading the
exploration and production of the Rovuma Basin
Area-1 while Eni is prospecting the Area-4.
In the Area-1 Anadarko is the operator with 26.5% of
the joint venture shared with Mitsui E&P (20%),
BPRL Ventures Mozambique (10%), Videocon
(10%), PTTEP (8.5%), ONGC Videsh (OVL) (10%)
and the local Empresa Nacional de Hidrocarbonetos
(ENH) holding the remaining (15%). In the Area-4,
the working interests are more concentrated since
Eni holds 50% shares of the joint venture with China
National Petroleum Corporation (PetroChina or
CNPC) (20%), Galp Energia (10%), Kogas (10%)
and ENH (10%). So far, Anadarko and Eni have identified more than 100 trillion cubic feet (tcf) and 70tcf
in the Area-1 and Area-4 respectively.
With such reserves the Mozambique Government required Anadarko and Eni to unitize the development of
the onshore part of their respective projects. As a consequence, Anadarko and Eni have organized a
competitive FEED to build series of 10 liquefied natural gas (LNG) trains at the Afungi LNG industrial Park
to be developed in the Cabo Delgado Province in the north of Mozambique.
In addition to this first Afungi onshore LNG project, Eni is prospecting other locations upper north of
Mozambique, close to the boarder with Tanzania, to install its own onshore facilities. So far Quionga, seems
to be Eni preferred choice for future Mozambique onshore LNG plants.
Anyway since the Australian experience, all the companies have experienced that building
large onshore LNG facilities carries on number of uncertainties related to the local acceptance
and the costs of such greenfield giant projects.
In this context, the risks associated to the innovative concept of FLNG look much more manageable for on-
time deliveries. Therefore in parallel to the onshore projects, Eni has defined its strategy to deploy of fleet of
three FLNG in the Area-4 that could run into production regardless the actual planning of the onshore
projects.
In order to design and build the first FLNG on fast track, Eni is planning to organize a competitive
FEED based on the pre-FEED completed by the tandem Saipem – Hyundai Heavy Industries (HHI).

During the pre-qualification process, Eni invited interested engineering companies to team up with
shipyards in order to present a complete offer combining both expertises. From the four or five qualified
tandems of engineering companies and shipyards, Eni should select only two to perform the FEED of the
first FLNG.
Then the tandem returning best FEED conclusions and submitting the best technical and commercial offer
for the engineering, procurement and construction (EPC) contract will be sanctioned the execution of the
construction in following its FEED. With this strategy, Eni and its partners , PetroChina, Galp Energia,
Kogas and ENH, are expecting to offload the first shipment from the first Rovuma Basin Area-1
Mozambique FLNG by 2019.
3- Eni considers own LNG Plant to secure 2018 shipment
The Italian national oil company Eni and its partners China National Petroleum Corporation (CNPC or
PetroChina), Kogas from South Korea, Galp Energia from Portugal and Mozambique Emprecia Nacional de
Hidrocarbonetos (ENH) are evaluating alternative solutions to develop its Mozambique liquefied natural
gas (LNG) project on fast track in order to load the first shipments in 2018.
Together with the
Texas-based
Anadarko Petroleum
Corporation
(Anadarko),
Eni managed to
unveil the gigantic
resources of natural
gas lying in the deep
offshore water
Mozambique. While
Anadarko was
leading the
exploration on the
Area-1 of the
Rovuma Basin,
Eni was confirming
the potential of the
region in the Area-4.
On the Area-1, Anadarko expect to accumulate 100 trillion cubic feet (tcf) of natural gas and Eni more than
70 tcf.
Geographically, Mozambique is perfectly located on the Africa East Coast to export LNG to Asia. In that
perspective, the Mozambique Government motivated the two teams leaders Anadarko and Eni to sign, end
of 2012, a memorandum of understanding (MOU) to develop jointly the onshore part of the Mozambique
LNG projects and coordinate their efforts regarding the offshore part where fields are linked between the
Area-1 and Area-4.
As a result, Eni and Anadarko have started the feasibility study to build the Afungi LNG Park in the Cabo
Delgado Province on the northeast coast of Mozambique. According to the reserves consolidated by Eni and
Anadarko, this onshore of the Mozambique LNG project is planned to be developed jointly in five different
phases of two trains per each phase.

Since the feasibility study has been completed for this onshore Mozambique LNG project, three teams of
engineering companies are bidding for the front end engineering and design (FEED) contract. Eni and
Anadarko had decided to call for tender on the base of a competitive FEED in order to save time on the
engineering, procurement and construction (EPC) phase of the project with already the target to ship
first LNGto Asia in 2018.
If it is clear that Anadarko is the operator of the Area-1 and Eni of the Area-4, the question is still pending
on the name of the operator of the jointly developed Afungi LNG Park.
This question will need to be answered before the final investment decision (FID) required to sanction the
competitive FEED to the winning engineering companies team. On Area-1, the Anadarko holds 36.5% with
Mitsui E&P 20%, BPRL Ventures Mozambique 10%, Videocon 10%, PTTEP 8.5% and ENH 15%.
On Area-4, the Italian leader Eni concentrates 50% through the joint venture Eni East Africa by which
PetroChina holds 20%, with the remaining shares being split between Kogas 10%, Galp Energia 10%, and
ENH 10%. With their deep pockets and 70% interests in the project, Eni and PetroChina do not intend to
lose time in the development of Mozambique LNG project.
In the same way as they are studying a floating liquefied natural gas (FLNG) solution to speed up the
development of the offshore part in Mamba , they are now considering to build their own LNG plant in
Quionga, close to Tanzania boarder.
In respect with the reserves in places in the Rovuma basin, Mozambique holds enough gas to feed the
Afungi LNG Park, Mamba FLNG and an additional Quionga LNG plant, that would secure first
LNG shipment for Eni and PetroChina from Mozambique LNG by 2018.

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Your partner in Energy Services
Khaled Malallah Al Awadi,
MSc. & BSc. Mechanical Engineering (HON), USA
ASME member since 1995
Emarat member since 1990
Energy Services & Consultants
Mobile : +97150-4822502
khalid_malallah@emarat.ae
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 years of experience in theof experience in theof experience in theof experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for EmiratesOil & Gas sector. Currently working as Technical Affairs Specialist for EmiratesOil & Gas sector. Currently working as Technical Affairs Specialist for EmiratesOil & Gas sector. Currently working as Technical Affairs Specialist for Emirates
General Petroleum Corp. “Emarat“ with externalGeneral Petroleum Corp. “Emarat“ with externalGeneral Petroleum Corp. “Emarat“ with externalGeneral Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most ofvoluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most ofvoluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most ofvoluntary 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 &the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor statgas compressor statgas compressor statgas compressor stations . Throughions . Throughions . Throughions . Through
the years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Manyof gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Manyof gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Manyof gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many
years were spent drafting, & compiling gas transportation , opyears were spent drafting, & compiling gas transportation , opyears were spent drafting, & compiling gas transportation , opyears were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference foreration & maintenance agreements along with many MOUs for the local authorities. He has become a reference foreration & maintenance agreements along with many MOUs for the local authorities. He has become a reference foreration & 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 andmany of the Oil & Gas Conferences held in the UAE andmany of the Oil & Gas Conferences held in the UAE andmany of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally , via GCC leading satellite Channels .Energy program broadcasted internationally , via GCC leading satellite Channels .Energy program broadcasted internationally , via GCC leading satellite Channels .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 28 August 2014 K. Al Awadi

New base special 28 august 2014

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New base special 28 august 2014