New base special 05 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,

redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained

in this publication. However, no warranty is given to the accuracy of its content . Page 1

NewBase 05 August 2014 Khaled Al

Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

15pc growth in Oman urea exports to India (OEPPA Business Development Dept).

Indian offtake of urea-fertiliser from the joint venture Oman-India Fertiliser Company (OMIFCO) rose 15.71 per cent during fiscal 2013/2014, according to figures made available by Indian authorities. Exports from OMIFCO’s Qalhat plant near Sur climbed to 2.121 million metric tonnes during the 12 months ended March 31, 2014, up from 1.833 million tonnes a year earlier, the Indian Federal Ministry of Chemicals and Fertilisers said in a statement.

Almost all of OMIFCO’s urea-fertiliser output, save for a small proportion earmarked for local distribution, is destined for the Indian market under a long-term urea offtake agreement (UOTA) between the Government of India and OMIFCO. Exports are routed via Indian fertiliser cooperatives IFFCO and KRIBHCO, both of which are shareholders (25 per cent each) in OMIFCO. Launching operations in 2006 with an investment of around $1 billion, OMIFCO has been manufacturing high quality urea-fertiliser at its state-of-the-art plant at Sur. The state-owned strategic investment vehicle Oman Oil Company represents the Omani government’s investment (50 per cent equity) in the project. Production is well-above the plant’s design capacity of 1.652 million metric tonnes of urea. Around 250,000 metric tonnes of ammonia is also produced annually as a byproduct of the urea manufacturing process. Last year, in a move designed to support the domestic agro sector, OMIFCO decided to set aside 30,000 metric tonnes of urea-fertiliser for distribution to local Omani farmers on an annual basis. It follows a successful pilot distribution scheme initiated by Takamul, the downstream investment arm of Oman Oil Company, in November 2011. Urea-fertiliser exports from OMIFCO during the first two months (April and May) of fiscal 2014/2015 totalled 341,000 metric tonnes, according to Indian authorities. India is one of the largest consumers of fertilisers in the world. It is also the third largest fertiliser producer globally with an installed capacity of 12.1 million tonnes of nitrogen based fertilisers and 5.6 million tonnes of phosphatic nutrient fertilisers. As of end-2012, around 30 major urea plants were in operation around the country.




Morocco: Galp's TAO-1 well offshore disappoints Source: Tangiers Petroleum

JV partner Tangiers Petroleum has provided an update on the TAO-1 exploration well located in the Tarfaya Offshore Block, Morocco.

The TAO-1 exploration well was designed to optimally test the Trident Prospect in carbonates of Middle Jurassic age. The well was drilled to a total depth of 3,518m MD and did not encounter favourable reservoir quality at Trident. As previously reported by Tangiers, (28 July 2014), no hydrocarbon shows were encountered at Assaka the younger secondary objective in the Upper Jurassic. The TAO-1 well will now be plugged and abandoned in line with standard industry practice. The exploration results from TAO-1 will be integrated into the regional basin analysis by Tangiers and its co-venture partners to further evaluate and assess the prospectivity of the Tarfaya Offshore Blocks I - VIII.

Tangiers' Managing Director, Dave Wall said: 'The Company is disappointed that success was not achieved at TAO-1 and we wish to thank our shareholders for their support over the recent challenging period. Tangiers Board and Management remains firmly focussed on creating value for shareholders and look forward to providing updates on New Ventures initiatives in the not too distant future.'




Galp Energia announces the conclusion of the drilling of the exploration well TAO-1, located in the Tarfaya Offshore area, in the Atlantic margin of offshore Morocco, where no hydrocarbons were encountered. The primary objective of the well was to test the resources potential of the Trident Prospect, located in the Middle Jurassic interval. The well was drilled at a total measured depth of 3,518 metres and did not encounter reservoir facies at the main target, Trident. The well also tested the prospect Assaka, located in the Upper Jurassic interval, and it also did not encounter hydrocarbons. The consortium is concluding operations and proceeding with rig demobilisation activities. Galp Energia and its partners will analyse the results obtained, namely geological data collected, using the data to evaluate the remaining prospectivity in the Tarfaya Offshore area.

This was the first offshore well operated by Galp Energia, where these activities progressed according to plan and with no Health, Safety and Environmental incidents, as a result of the rigorous procedures adopted.

Galp Energia is the operator of the Tarfaya Offshore area with a 50% stake in the consortium which holds eight offshore exploration licences in the area, known as the Tarfaya Offshore I and VIII. The consortium is formed by Tangiers Petroleum (25%) and by ONHYM (25%).

About Morocco oil & Gas

1. Morocco is a net hydrocarbon importer. The country produces marginal amounts of crude oil, natural gas, and refined petroleum products, which is mainly consumed domestically. Morocco has two oil refinery with a total crude oil distillation capacity of nearly 155,000 barrels per day (bbl/d).

2. Morocco produced 5,100 bbl/d of petroleum and other liquids in 2012, up only slightly over the past decade from

3,700 bbl/d in 2003. Dry natural gas production in Morocco has been relatively steady over the past decade, with 2 billion cubic feet (Bcf) produced in 2011.

3. Recently there has been increased interest in upstream activities, largely because Morocco is believed to hold untapped shale resources, and the country also offers favorable fiscal terms for foreign investment in the energy sector.

4. With most of its energy needs met by importing hydrocarbons, Morocco wants to reduce its dependence on foreign imports by developing renewable energies to meet domestic electricity needs. The state-owned Office National de l'Electricite (ONE) plans to harness solar and wind energy to generate about 42 percent of the country's electricity need by 2020, according to the Arab Oil and Gas Journal.

5. A portion of the Maghreb-Europe Pipeline (also known as the Pedro Duran Farell pipeline), which transits natural gas between Algeria and Spain, passes through Morocco. In lieu of transit fees, Morocco receives around 21 Bcf of natural gas from the Europe Maghreb Pipeline Limited every year.

6. According to a recent EIA study, Morocco has 20 trillion cubic feet (or 0.2 billion barrels) of technically recoverable shale oil and gas resources, mostly in the Tindouf basin, with smaller amounts in the Tadla basin.




Shell & Nigeria Gov’t do nothing to clean up Niger Delta pollution Aamnesty international + NewBase

Environmental organisations have launched a report in which they accuse Shell and the

Government of Nigeria of a “shocking lack of action” with regards to the clean-up of pollution

in the Niger delta.

Friends of Earth Europe, Amnesty International, Environmental Rights Action, Platform and the Centre for Environment, Human Rights and Development (CEHRD), today issued a ” damning” report, which the organisations say exposes “a shocking lack of action” by Shell and the Nigerian Government to clean up the widespread pollution in Ogoniland, despite recommendations made by a major UN study three years ago today.

The UN Environment Programme published a scientific study on the Ogoniland region of the Niger Delta in 2011, exposing extensive oil pollution, severe health risks for the population – including previously unacknowledged pollution of drinking water – and fundamental failures in Shell’s processes for cleaning up oil spills, the organisations say.

Godwin Ojo of Friends of the Earth Nigeria said:“Three years on and the government and Shell have done

little more than set up processes that look like action but are just fig leaves for business as usual. The lack

of meaningful action in the face of incontrovertible scientific evidence is outrageous. The Nigerian

government and Shell are quite simply getting away with environmental and human rights abuses in the

Niger Delta.”

The UN study, conducted at the request of the Nigerian government and paid for by Shell, exposed the serious failure of the Nigerian government to regulate and control companies like Shell. The report also revealed Shell’s systemic failure to address oil spills going back many years. The UN described how sites that Shell claimed were cleaned up were found by UN experts to be still polluted.




Audrey Gaughran of Amnesty International said:“No matter how much evidence emerges of Shell’s bad

practice, Shell has so far escaped the necessity to clean up the damage it has caused. The UNEP report was

clear: Shell did not clean up oil spills properly. Its clean-up system was critically flawed and the

consequence has been long-term exposure of tens of thousands of people to pollution and health risks.”

Since the 2011 UN study, Shell has defended, and continues to use, methods for cleaning oil spills declared ineffective by the UN report, Amnesty International claims.

Amnesty International further says that the ‘No progress’ report also highlights Shell’s “manipulation of

information to avoid accountability for old and leaking pipes – pipes so old the company will not disclose

their age or condition.”

Paul de Clerk of Friends of the Earth Europe said:“Three years after finding out that their operations have

exposed almost every man, woman and child in Ogoniland – and almost certainly tens of thousands of

people in others parts of the Niger Delta – to lifelong pollution, Shell is still more concerned with protecting

itself. Governments of Nigeria and the home countries of Shell, Netherlands and the UK, should make sure

that Shell starts a proper clean up and compensates the damage.”

The UN study also recommended, amongst other measures, the establishment of an Ogoniland Environmental Restoration Authority and the establishment of an Environmental Restoration Fund with an initial capital of USD $1 billion. Neither of these has been established, the environmental organisations say.

The Nigerian government, Shell, and its home governments – the UK and the Netherlands – have all benefitted from oil extraction in the Niger Delta and should now support a social and environmental rehabilitation process and the implementation in full of the UN study, according to the organisations.




Nigeria: CAMAC Energy discovers additional reserves at the Oyo field, offshore Source: CAMAC Energy

CAMAC Energy has announced the preliminary results of a successful Oyo field development well offshore Nigeria in

OML 120. The Oyo-8 well commenced drilling operations on June 15, 2014 and has both a vertical and a horizontal

section. The vertical section was designed to test for additional hydrocarbons in the previously undrilled Eastern

fault block of the Oyo field. CAMAC Energy is pleased to announce Oyo-8 was drilled to a total depth (TD) of 6,059

feet, and successfully encountered four new oil and gas reservoirs with total gross hydrocarbon thickness of 112 feet

based on results from the logging-while-drilling (LWD) data, reservoir pressure measurement, and reservoir fluid

sampling. The well will now be completed horizontally as a producing well in the Pliocene formation of the Central

Oyo field. Oyo-7, which was successfully drilled in October 2013, will also be completed horizontally in the Pliocene

formation of the Central Oyo field.

Management Comments

'This is an excellent result from the vertical section of Oyo-8, as it positively established oil presence in new reservoirs in the Eastern fault block. We have commenced a detailed evaluation of the results with a view to establishing the size of the incremental reserve additions,' said Segun Omidele, Senior Vice President of Exploration and Production. 'We are one step closer to bringing these two high-impact development wells on production that will generate immediate revenues, cash flow, and earnings for our shareholders.'




Oman’s exports drop 8 per cent on decline in oil revenue BYTIMES NEWS SERVICE = OMAN

The total value of Omani exports, which include oil and gas, non-oil products and re-exports, declined by 7.9 per cent, totaling OMR5.14 billion by the end of the first quarter of 2014, compared with OMR5.58 billion registered during the same period in 2013. Recently released foreign trade figures issued by the National Centre for Statistics and Information (NCSI) revealed the decline was due to a 9.3 per cent fall in oil and gas exports by the end of the first quarter of 2014, when compared with the same period in 2013, generating export

revenue of OMR3.37 billion by the end of March, 2014, when compared with OMR3.72 billion by the end of March, 2013. During the same period, the total value of re-exports declined by 27.2 per cent recording a total value of OMR760.6 million by the end of the first quarter of 2014 against OMR1.04 billion in the same period last year. Within the exports category, the only increase recorded was in the non-oil exports which grew by 23.4 per cent totalling some OMR1.01 billion at

the end of March 2014 compared with OMR818.2 million during the same period in 2013. The growth in the non-oil exports is largely due to the increase in mineral products exports, rising 69.2 per cent from OMR213 million registered by the end of March 2013 to OMR360.4 million during the first quarter of 2014. According to the NCSI foreign trade report, the total value of merchandise imports declined by 8.1 per cent, totaling OMR2.94 billion by the end of March 2014 compared to OMR3.20 billion during the same period in 2013. The total volume of merchandise imports by volume registered a drop of 7.4 per cent by the end of March 2014, totaling 5.98 million tonnes compared with 6.46 million tonnes recorded during the same period in 2013. The total value of merchandise imports arriving via sea routes dipped by the end of March 2014 to OMR1.93 billion compared to OMR2.31 billion during the same period in 2013, representing a decline of 16.3 per cent. Meanwhile, when measured by volume, imports by sea increased by 6.2 per cent to 3.87 million tonnes by the end of March 2014 when compared with 3.65 million tonnes during the same period in 2013. Additionally, the total value of the merchandise imports arriving via land routes grew by 28.5 per cent recording OMR789.2 million by the end of March 2014, compared with OMR614.2 million during the same period in 2013. However, the total volume of merchandise arriving via land outlets declined by 24.8 per cent dropping from 2.8 million tons by the end of March 2013 to 2.10 million tonnes during the same period in 2014. Over the same period, the total value of merchandise imports arriving via air routes declined by 21.2 per cent recording OMR215.5 million compared with OMR273.5 million by the end of March 2013. Additionally, the total volume of merchandise arriving via air outlets recorded a drop of 39.1 per cent with 11,300 tonnes recorded by the end of March 2014 compared with 18,600 tonnes during the same period in 2013.




India: Oilex provides Cambay-77H update Source: Oilex+NeewBase

• Light crude oil continues to be recovered

• Frac water flow-back continues with ~ 55%

recovered

Oilex has announced that Cambay-77H well continues to produce crude oil and frac water and ~ 55% of the water used to stimulate the well has been recovered. Light crude oil continues to be recovered and most has been transported to a nearby refinery for sale. Gas produced concurrently with crude oil during well flow-back continues to be flared to ensure safety of all well-site personnel.

No proppant has been recovered at surface subsequent to the milling operations and initial well bore clean out.

No evidence of formation water has been seen at surface during the flow-back and this is interpreted to support Oilex's hypothesis that formation water production is not occurring.

The well planning including flow-back and clean-up was predicated upon gas and condensate and the recovery of crude oil and gas may influence the duration required for Cambay-77H to clean-up prior to commencement of any production testing. Samples of the oil, gas and water have been collected for laboratory analysis. These analyses will assist in determining the fluid properties being recovered from the well.

During flow-back operations the following activities have been completed which have necessitated shutting in the well or limiting flow:

• Change of frac tree to the standby frac tree because of leak issues

• Completed two runs to the toe of the well with the coiled tubing unit

• Preliminary build up surveys of wellhead pressure

The coil tubing unit, which was retained at Cambay-77H site as a precaution, has now been demobilised along with other ancillary equipment, reducing the daily operating costs. Oilex will advise the market of a stabilized flow rate via a production test once frac fluid return and clean-up operations have been completed.

Managing Director of Oilex, Ron Miller, said:

'The ongoing recovery of light crude oil during flow-back operations is particularly welcome. Flow-back started very strongly and continues at a steady pace, although the shut-in periods for changing the frac tree and checking the well bore have extended the duration. As this is the first multi-stage fracture stimulated well to flow-back in the Cambay Basin, there is no benchmark for comparison. Oilex looks forward to commencing the production testing after sufficient frac fluids have been

recovered from the well and the flow has stabilised.'




GE investing USD 2 Bln in development across Africa Press Release, GE + NewBase

GE will invest $2 billion in facility development, skills training, and sustainability initiatives across Africa by 2018.

GE made the announcement in advance of President Obama’s U.S.-Africa Leaders Summit, where GE is hosting African and global government officials, policy experts, NGOs, entrepreneurs and business leaders for a conference on investment, infrastructure, and innovation in Africa.

Through partnerships and technology, GE is poised to help increase access, reliability, and affordability of core infrastructure throughout the continent. Africa has emerged as the most promising growth region for GE. Total GE revenues

in Africa in 2013 were $5.2 billion and in the past year, GE has won more than $8.3 billion in orders across Africa.

GE Chairman and CEO Jeff Immelt said, “I am proud of our 100-year history

in Africa. Through investments such as our new multi-modal manufacturing

facility in Nigeria, Algeria gas turbine manufacturing, and our customer

innovation center in South Africa, we remain a committed partner to Africa’s

sustainable growth.”

GE will focus its investment in Africa in three strategic areas: building infrastructure; delivering localized solutions to customers; and capacity building, by providing skills training and growing supply chain development in local communities.




US: Bakken fuels North Dakota’s oil production growth Source: U.S. Energy Information Administration,. North Dakota crude oil production surpassed 1.0 million barrels per day (bbl/d) in April and May (the latest data available). This record is the result of increasing crude oil production from the Williston Basin's Bakken and Three Forks formations in North Dakota and eastern Montana.

Although Bakken oil production initially began in the 1950s at Antelope Field in North Dakota, large-scale production growth did not begin until after the discovery of the Parshall Field in 2007.

Since then, advances in drilling methods and technology, a better understanding of the geology of the Bakken, higher crude oil prices, and the formation's large size and number of wells all have contributed to higher production and to the potential for continued future growth.

As more wells are drilled in the Bakken, the base resource becomes better defined. Because the Bakken has a relatively low thickness (not exceeding 250 feet) and low permeability, better information on the location of available resources can quickly translate into an increase in crude oil production volumes.

Defining the resource in any formation is critical in forecasting the growth and sustainability of its oil and natural gas production. Factors such as the geologic extent, depth, thickness, and porosity of a formation can inform the estimated ultimate recovery (EUR) rate of wells that are drilled in a formation. EIA uses geologic data to better understand individual well performances and the expected EUR in the Marcellus Shale, and plans to expand these efforts over time to include other formations throughout the United States, including the Bakken.

EIA uses well data to create maps showing the extent and structure of the productive and prospective regions of the Bakken. These maps help to visualize the depth and relative thickness of the Bakken formation. In addition, depth maps define the region where the resource is within optimal drilling range. Three-dimensional thickness maps can be used to determine rough estimates of resources in this region, as well as structural features such as faults and folds.




NewBase Special report: Azerbaijan Key Projects and

Business highlights 2014

Occupying one of the richest coast of the Caspian Sea in oil and gas resources, the Republic of Azerbaijan is taking a strategic place between Asia and Europe, between Russia and Middle-East countries.

Under the coordination of the State Oil Company of Azerbaijan (SOCAR) these oil and gas resources were explored and developed smoothly in joint venture with international oil companies (IOCs) because of the lack of export infrastructures across the neighboring countries, especially Georgia and Turkey.

Anyway, since 1992, date of SOCAR registration, companies such as BP, Inpex, Chevron, Hess, Statoil and Total acquired a significant expertise is exploring and producing in the offshore fields of the Caspian Sea.In doing so they prepared ground to take a leap as soon as Azerbaijan should be directly linked to western Europe. During years, multiple projects of giant pipelines projects were studied technically, commercially and politically using different routes by the north or the south up to the European gas grid.But in selecting the Trans-Adriatic Pipeline (TAP) project over the famous Nabuco on July 2013, BP and

its partners in the Shah Deniz Phase-2 project, triggered a cascade of investments in multiple projects in Azerbaijan.

Total to focus on Caspian Sea Absheron gas field

The French major Total and its partners, the State Oil Company of Azerbaijan Republic (SOCAR) and the other French oil and gas company GDF-Suez, are finalizing the conceptual design to develop the Absheron offshore gas field in the Azerbaijan Caspian Sea. This decision on the design to be detailed and implemented appears as a key milestone in the Absheron project development for all partners.

It comes in following series of Total announcements about selling its working interests in different projects related to the Shah Deniz Full field Development. In December 2013, Total decided to pull out from the joint venture to build and operate the Trans Anatolia Natural Gas Pipeline (TANAP) project to carry out Shah Deniz gas from Azerbaijan to Greece through Turkey.

In May 2014, Total published a press release to explain that it is selling its 10% stake in Shah Deniz and the South Caucasus Pipeline to the Turkish national oil company (NOC) TPAO. In June 2014,




Total communicated its intention to withdraw from the last section of the pipeline from Greece to Italy and known as Trans Adriatic Gas Pipeline (TAP) project.

Although Total is present in Azerbaijan since 1995, this cascade of publications could have indicated a general withdraw from this country. But Total had only a minority share in these giant projects while it discovered in 2011 the Absheron liquid-rich offshore gas field in the central area of the Azerbaijan Caspian Sea.

In Absheron, Total and its partners are sharing the working interests as following:

- Total 40% is the operator - SOCAR 40% - GDF-Suez 20% Located approximately 100 kilometers southeast of Baku, Absheron is lying just beyond the continental shelf by 500 meters of water depth and 7,000 meters of total depth. From the current estimations resulting from three years of exploration, Total and its partners, Absheron should hold 5 to 10 trillion cubic feet (tcf) of natural gas.

In addition to this non-associated gas reserves, Absheron appears to be rich of condensate still under evaluations. In this context, Total made the decision to re-allocate its interests in Azerbaijan and to concentrate its financial effort from Shah Deniz to Absheron where it operates. Because of its size, Total and its partners are planning to develop Absheron in phases in similar way as Shah Deniz.

Even though Total withdrew from Shah Deniz project and all related infrastructures, it will contribute directly to the optimization of these assets as Total is planning to export Absheron gas and condensate through BP and SOCAR Sangachal Terminal and the Southern Corridor Pipeline project.

For Absheron Phase-1, Total should spend $5 to $7 billion capital expenditure including:

- Subsea production system with four subsea wells - Offshore platform - Export pipeline system to the Sangachal Terminal In order to save costs, the Absheron offshore platform should be located on the continental shelf of the Caspian Sea by only 100 meters of water depth and should have a capacity of 500 million cubic feet per day (cf/d) of natural gas. From the actual design concept, Total and its partners, SOCAR and GDF-Suez are preparing to move into the front end engineering and design (FEED) work of the Absheron Phase-1 project in expecting the first production by 2021.

BP and Socar to boost Azerbaijan ACG Full Field

As the operator of the Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea ofAzerbaijan, Azerbaijan, BP shared with his partners, the State Oil Company of Azerbaijan (Socar), Inpex, Chevron, ExxonMobil, Statoil, TPAO, Itochu and ONGC Videsh, in the Azerbaijan International Operating Company (AIOC) his recommendations to maintain production up to 2024 and beyond. Discovered in the 1980s by the Soviets approximately 100 kilometers east of Baku by less than 180 meters water depth in the Caspian Sea, the three crude oil fields Azeri, Chirag and Gunashli appeared quickly from first exploration to be as large as complex to develop.




The national oil company (NOC) Socar started the first production with several shallow water platforms in 1985. But in 1994, the Government of Azerbaijan established the AIOC joint venture to sign a 30 years production sharing agreement (PSA) covering the development of the ACG oil and gas fields.

Led by BP, the AIOC joint venture consolidates the working interests of the stakeholders such as:

- BP 35.8% is the operator - Socar 11.6% - Chevron 11.3% - Inpex 11% - Statoil 8.6% - ExxonMobil 8% - TPAO 6.8% - Itochu 4.3% - ONGC Videsh 2.7% The AIOC production sharing agreement is supposed to last until 2024, leaving the Government of

Azerbaijan and its national flagship Socar to take the lead afterward. In that perspective BP mobilized all its experience and knowledge about the ACG oil fields to figure out the potential scenari to continue their development beyond the production sharing agreement deadline.

New Western Chirag platform to add 100 Kb/d to AIOC

With total reserves estimated to 17.4 billion barrels of oil, ACG ranks among the largest fields in the world.At the end of the production sharing agreement, in 2024, BP estimates that only 5.4 billion barrels of oil will have been recovered, leaving still a long life to the ACG fields.

As the ACG oil field development provides the Azeri Government with the most significant revenues, it intends to prepare the next phase carefully to prevent any slowdown in production. In that respect the last years experiences is rich of learning.

In completing the ACG Phase III project in 2008, the AIOC joint

venture was expecting to reach 1 million barrels per day (b/d). Since then, the production peaked up only to 823,000 b/d in 2010 and started to decline again.




Fortunately the last platform of the ACG Full Field Development program started operations at Western Chirag on early February. It should bring 100,000 b/d additional production of oil to the AIOC joint venture, shortly below the targeted 1 million b/d still.

From the modelizations tested by BP through digital oil fields techniques, it appears that solutions to prevent the early depletion of the ACG oil field should be to add two offshore production platforms to increase the pumping operations and gas injection capacities. In order to maintain the ACG production at the level required by the production sharing agreement, the second platform should be in operation by 2021 at the very last limit.

Considering a minimum lead time of three to four years to design and build these platforms, BP and its partner in the AIOC joint venture Socar, Chevron, Inpex, Statoil, ExxonMobil, TPAO, Itochu and ONGC Videsh should make a decision to proceed with the first production platform before 2015.

BP, Socar, Statoil, Total make FID on Shah Deniz

The London-based BP and its partners, Statoil from Norway, the State Oil Company of Azerbaijan (SOCAR), Total from France, Lukoil from Russia, the National Iran Oil Company (NIOC), and Türkiye Petrolleri Anonim Ortaklığı (TPAO) from Turkey, have made the final investment decision (FID) for the Shah Deniz Stage-2 project in Azerbaijan.

Located approximately 70 kilometers southeast of Baku by 600 meters of water depth in the Caspian Sea, Shah Deniz is the largest gas and condensate field known in Azerbaijan. Shah Deniz Stage-1 started production in 2006 and since then it delivers 860 million cubic feet per day (cf/d) of natural gas.

With the Shah Deniz Stage-2, BP and its partners are proceeding to the Shah Deniz full field development (FFD) in order to add 1,600 million In making this FID on the

Shah Deniz Stage-2 development, BP and its partners agreed on a cascade of additional projects to:

- Double the South Caucasus Pipeline (SPC) across Azerbaijan and Georgia - Build the Trans Anatolian Gas Pipeline (TANAP) through Turkey - Construct the Trans Adriatic Pipeline (TAP) from Turkey to Italy through Greece and Albania




The whole project will require $45 billion capital expenditure out of which the Shah Deniz Stage-2 and the SPC projects will represent $28 billion investment. Despite the size these projects and the quantity of gas exported to Europe, the Shah Deniz full field development will represent only 2% of the European natural gas consumption.But the selection of this Southern Gas Corridor to Europe has been decided in

expecting additional sources of supply coming from other fields in Azerbaijan, but also from the north of Iraq and later on from Iran. Because of the giant size of each individual projects,BP and its partners have taken different stakes in each section.

Statoil has decided to sell 10% shares in the Shah Deniz and SCP projects, so that BP remains the operator with working interests such as:

- BP 28.8% - SOCAR 16.7% - Statoil 15.5% - Lukoil 10%. - NIOC 10% -Total 10% - TPAO 9% In parallel Statoil will take 20% share in TAP project but will stand out of TANAP project. The challenges of the Shah Deniz Stage-2 project relies not only in its size and location but also in the high pressure and high temperature of the reservoir.

For this Shah Deniz full field development, BP and its partners are planning to build:

- Two offshore bridge-linked platforms - 26 drilling wells - Gas gathering systems with 500 kilometers of subsea pipelines - Additional gas central processing facilities at the existing Sangachal terminal In making the final investment decision now, BP and its partners, Statoil, SOCAR, Total, Lukoil, NIOC, and TPAO are targeting the first production in 2018 with first deliveries in Europe through the TANAP and TAP pipelines projects in 2019.




Socar awards contracts for new Azerbaijan Ammonia

The national State Oil Company of Azerbaijan Republic (Socar) selected the Danish catalysis expert Haldor Topsoe to provide its first integrated fertilizer project in Azerbaijan with its ammonia technology. With a budget of $650 million capital expenditure, the Republic of Azerbaijan has made the final investment decision (FID) to build the country largest ammonia and urea integrated fertilizer plant in the country. This fertilizer plant should be located at the Sumgayit City 35 kilometers north of the capital Baku, along the Caspian Sea.

From this position, this Socar greenfield fertilizer project will receive its natural gas feedstock directly from the neighboring offshore giant gas fields. This nitrogen fertilizer project belongs to the State Program 2008 – 2015 to sustain the effective development of the agriculture and the food industry in the Republic of Azerbaijan. Therefore the national oil company Socar has been mandated to build and operate this new plant. In this context and as part of its mandate, Socar is due to adopt the state-of-art technologies to design this greenfield fertilizer plant so that it will meet all the international standards of quality and performances. The Socar Sumgayit fertilizer project is 100% financed by the Government.

Socar allocated 24 hectares of land in its Azerkimya plant and proceeded to the revamping of the existing

transportation infrastructures to prepare the ground for the coming nitrogen fertilizer plant.

In March 2012, all the pre-qualified companies submitted their best technical and commercial offer for the Azerbaijan Fertilizer engineering, procurement and construction (EPC) contract out of which the South Korean Samsung Engineering (Samsung) was selected on a lump sum turn key basis.

In March 2013, Samsung signed the EPC contract for an amount of $650 million including the selection of the process technologies and the pre-commissioning of the nitrogen fertilizer project. According to the terms of the contract Samsung will build an integrated ammonia plant and urea plant.

The ammonia production unit should have a capacity of 1,200 tonnes per year (t/y).

The urea production unit should be designed for a capacity of 2,000 t/y.

Since the EPC contract signed, Socar and Samsung proceeded to the evaluation of the process technologies for the respective production units.

They selected the Danish catalysis expert Haldor Topsoe to provide the licence for the ammonia production unit and the Dutch company StamiCarbon from the Italian engineering group Maire-Tecnimont SpA, as licensor of the urea technology.

Since the main contracts have now been awarded to Samsung, Haldor Topsoe and StamiCarbon, Socar is expecting the project execution to begin in following in order to start the commercial operation of the first integrated Azerbaijan fertilizer plant by 2016.




Dubai Clean energy Forum focus on Dubai Energy- Sep.22 http://www.cleanenergydubai.com +NewBase

A major conference aimed at providing a roadmap on how Dubai will meet the requirements of the 2030

energy strategy will be held in Dubai in September.

Dubai Clean Energy Forum, organised by Meed in partnership with Ministry of Energy, Dubai Electricity and Water

Authority (Dewa), Supreme Council of Energy and Ministry of Foreign Affairs, will be conducted from September 22

to 25 at The Address Hotel Dubai Mall.

The forum is designed to be the definitive platform for all those seeking to participate in the emirate's drive towards the use of sustainable energy.

The conference comes at a pivotal time as Dubai opens its power sector to the private sector with two high-profile IPP Projects scheduled for late 2014 - 100MW 2nd phase of the Mohammed bin Rashid al-Maktoum Solar Park and the 1200MW clean coal power plant project.

The conference will showcase activities being developed in Dubai (led by Dewa) to develop new projects, adopt cutting-edge technologies and implement new legislation to ensure that every initiative is aligned with Dubai's integrated energy strategy and its preparations for Expo 2020.

Topics include:

• Detailing DEWA's long-term energy vision - an update on the Dubai Integrated Energy Strategy 2030 • Dubai's power sector- what new opportunities exist for investors? • Accelerating the plans for the development of the solar sector in Dubai (feed-in tariffs, PV rooftop

programme etc) • Understand the track record of Solar's performance in the UAE: what has been learnt? • Detailing the Expo 2020 sustainability legacy • Renewables finance in GCC (designing competitive and bankable projects) • Developing a clean energy sector across the region; learnings from across the GCC • Practical application of energy efficiency technologies in DubaiGreen Building Codes and Regulations in Dubai

Date: 22 – 24 September

2014. Venue: The

Address, Dubai Mall,

Dubai, United Arab

Emirates




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

[email protected]

[email protected]

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 of of of

experience in theexperience in theexperience in theexperience in the Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as

Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for

the Gthe Gthe Gthe GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations ManagCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations ManagCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations ManagCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in er in er in er in

Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has develoEmarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has develoEmarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has develoEmarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed great ped great ped great ped great

experiences in the designing & constructingexperiences in the designing & constructingexperiences in the designing & constructingexperiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. 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 wMany years were spent drafting, & compiling gas transportation , operation & maintenance agreements along wMany years were spent drafting, & compiling gas transportation , operation & maintenance agreements along wMany years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local ith many MOUs for the local ith many MOUs for the local ith many MOUs for the local

authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andauthorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andauthorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andauthorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted Energy program broadcasted Energy program broadcasted Energy program broadcasted

internationally , via GCC leading satellite Channels . internationally , via GCC leading satellite Channels . internationally , via GCC leading satellite Channels . 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 05 August 2014 K. Al Awadi

Economy & Finance

New base special 05 august 2014