new base special 15 may 2014

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NewBase 15 May 2014 Khaled Al Awadi

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Yokogawa wins key deal for Jeddah power plant Press Release

Yokogawa Electric Corporation has won an order from Hyundai Heavy Industries to supply various systems and products for Stage-1 of the Jeddah South supercritical oil-fired thermal power plant 1 project in Saudi Arabia.

The joint order recipients are Yokogawa Electric and a subsidiary, Yokogawa Middle East & Africa, said a statement. The order includes control systems, safety instrumented systems, analysis systems and other products.

Jeddah South will be Saudi Arabia’s first supercritical thermal power plant, and is being built by a state-owned Saudi Electricity Company. Stage-1 of this project involves the construction of four 723 MW units producing a total of 2,892 MW. Unit 1 is scheduled to start operation in 2017.




For each of the four units, Yokogawa will supply the following:

1. Centum VP R5 integrated production control system for the control of the boiler and its auxiliary facilities, including all IEC61850-based electrical systems; a ProSafe-RS safety instrumented system (SIS); an ExaquantumTM plant information management system (PIMS); a plant operation training simulator .

2. PK200 current-to-pneumatic converters.

3. Liquid analysis system consisting of conductivity, pH, and residual chlorine analyzers. 4. Duct gas analysis system consisting of oxygen, infrared gas, and TDLS200 tunable diode laser analyzers.

Yokogawa Saudi Arabia, a subsidiary of Yokogawa Middle East & Africa, will be responsible for the engineering and commissioning of the DCSs, SISs, and PIMSs. Yokogawa Electric and Yokogawa Electric Korea will be responsible for the engineering and delivery of the current-to-pneumatic converters and the analysis systems, said the statement.

Yokogawa has executed a number of large oil and gas and petrochemical projects and provided more than 80 control systems for power plant and power plant utilities throughout the Middle East.

Supercritical thermal power plants are highly efficient and produce fewer greenhouse gases than conventional power plants, and it is expected that more plants of this type will be constructed in Saudi Arabia and other countries.

Highly Reliable Controller

- Seven 9s system availability (99.99999% uptime) - Pair-and-spare technology -- - 1 Gbps control LAN (Vnet/IP)

- 1 msec SOE resolution --- Online maintenance - Compact Components




Taqa Q1 net profit jumps 158% Reuters

Abu Dhabi National Energy Company (Taqa), the state-owned oil explorer and power supplier, posted a 158-percent jump in first-quarter net profit on Wednesday as revenue from its oil and gas business soared.

Taqa, 75 percent owned by the government of Abu Dhabi, made a profit of 274 million dirhams ($74.6 million) in the three months to March 31, up from 106 million dirhams a year earlier, it said in a statement. Taqa's quarterly oil and gas revenue was 3.5 billion dirhams, up from 2.2 billion dirhams in the prior-year period. This helped push overall revenue to 7.2 billion dirhams, up 33 percent year-on-year.

"Our first quarter result was helped by the restoration of North Sea oil production at Cormorant Alpha and higher natural gas prices in North America, but we also demonstrated our ability to increase capital efficiency and control costs," Stephen Kersley, chief financial officer of Taqa, said in the statement.

"We are well positioned with ample liquidity, and look forward to driving continued improvement in earnings and coverage ratios. "Taqa has investments around the world, including North Sea oil production facilities and power plants in India, Ghana and Morocco.

In April, Edward LaFehr took over as chief operating officer, heading the firm after CEO Carl Sheldon stepped down after six years in February. Late last month, Taqa finalised a ten-year $750 million bond, the proceeds of which would be partly used to repay a $1.2 billion bond due to mature in September 2014. Taqa also signed a $200 million yen-denominated loan to partly fund repayment of the September bond. -




Aramco, Sumitomo face higher costs for petchem plant expansion

The expansion of a petrochemicals complex in Saudi Arabia owned by Saudi Aramco and Sumitomo Chemical is now expected to cost 32bn riyals ($8.5bn), higher than previously estimated, the joint-venture said yesterday.

The expansion plan, which aims to increase output from the plant as well as introduce higher-margin products, was originally estimated to cost around $7bn. But in a stock exchange filing yesterday, PetroRabigh said: “Total investment in the project is around 32bn riyals according to current forecasts.”

The statement did not give any reason for the change in price, but said the project - situated on Saudi Arabia’s Red Sea coast - was still due to come online during 2016. A company spokesman declined to provide further information.

The joint-venture, known as PetroRabigh, has had a number of setbacks because of maintenance issues in 2013 at its existing facility including power cuts and an outage at its ethane cracker. A new marketing deal with its parent firms in December has helped alleviate the pressure on profits

from the maintenance problems. Both Aramco and Sumitomo have also made firm commitments to the expansion project, known as Rabigh II, since giving it the final go-ahead in 2012.

Under the plan, an existing ethane cracker will be expanded and a new aromatics complex built that will make higher-value petrochemical products and have a capacity of 1.72mn tonnes per year. PetroRabigh’s existing plant can produce an annual 18mn tonnes of

refined products and 2.4mn tonnes of petrochemical products.

Rabigh II will produce ethylene propylene rubber (EPR), thermoplastic polyolefin (TPO), methyl methacrylate (MMA) monomer, polymethyl methacrylate (PMMA) among other products.

To fund construction of Rabigh II, both Sumitomo and Aramco will put in around £100bn, with the rest coming from project financing, Sumitomo Chemical President Masakazu Tokura told reporters in November.




Libya’s El Feel oilfield restarts; El Sharara closed Reuters/Tripoli

Libya’s El Feel oilfield has restarted production, National Oil Corp (NOC) said yesterday, as it moves slowly to restore some output following protests that closed fields and ports.

The government said on Monday it had reached an agreement with protesters to reopen the western El Sharara, El Feel and Wafa oilfields and the pipelines connecting them to the Zawiya port.

Expectations and doubts about the return of the oilfields have driven global oil prices this week.

The El Sharara oilfield, the largest at 340,000 bpd, was still closed yesterday, because protesters had not yet opened the pipeline valve to the port, field manager Hassan Sadiq said.

“They (protesters) reopened the valves for the Wafa and El-Feel oil fields but not for Sharara,” he said. “We are ready to resume work once the valves are reopened.”

NOC spokesman Mohammed El Harari said El Feel was pumping more than 35,000 bpd, helping to slightly boost national output to 250,000 bpd, still

far short of Libya’s roughly 1.4mn bpd before the protests started. El Feel, which has a pre-shutdown production capacity of 85,000 bpd, is jointly operated by NOC and Italy’s ENI.

Harari said gas was flowing from Wafa, but he did not know whether pumping of liquid condensates had resumed. Three years after a NATO-backed revolt toppled Muammar Gaddafi, Libya’s oil infrastructure remains the target of protests and shutdowns, usually by brigades of former rebels who refuse to disarm or recognise the state’s authority.




The western pipeline network has been closed by protesters since March, forcing the shutdown of the fields. Analysts say Libya’s oil output is vulnerable to new and continued protests, given that opposition groups are fractured and lack a joint leadership.

In the east of Libya, a government deal to reopen two major oil ports controlled by another rebel movement looks likely to unravel over the movement’s opposition to the appointment of a new prime minister.

The deal reached in April led to the reopening of the two smaller eastern terminals of Hariga and Zueitina, but the larger ports of Ras Lanuf and Es Sider remain shut pending more talks.

As a result of protests at ports and at some oil fields, crude oil production fell to 1.0 million bbl/d in July and 600,000 bbl/d in August, although the production level at the end of August was far lower. At the end of August, members of the Zintan militia blocked pipelines that connect the El Sharara and El Feel (Elephant) fields to the Zawiya and Mellitah export terminals, respectively, forcing the shutdown of those fields. Production dropped to around 200,000 bbl/d during this time period and continued at this level into September. In mid-September production at the western oil fields restarted and boosted Libya's total output, albeit it remained less than half of its effective capacity.

Libya also produces an estimated 120,000 to 140,000 bbl/d of non-crude liquids, which include condensate and natural gas liquids. These non-crude liquids mainly come from the Mellitah gas processing plant, a gas processing plant at the Intisar complex, and a natural gas liquids plant in Marsa al-Brega.




Bahrain to increase Tatweer associated gas monetization

While Tatweer Petroleum (Tatweer) is increasing its oil and gas production from the Bahrain Field, Bahrain National Gas Company (Banagas) is considering the expansion of its Sitra gas processing facilities with the addition of a third train.

Covering 80 percent of Bahrain main island, the Bahrain field was discovered in 1932 with a reservoir lying by depth ranging between 400 meters and 2,200 meters below the surface. In exploration and production for eighty years, the Bahrain field supplies the Sitra refinery operated by the national oil company (NOC) Bahrain Petroleum Company (Bapco).

Until 1979 the crude oil produce from Bahrain field was treated in the refinery while the associated gas was just flared.

In 1979, the Kingdom of Bahrain established Banagas to capture the associated gas from the Bahrain field, treat it and monetize it through the condensate.

Banagas was formed as a joint venture between three stakeholders:

- Government of Bahrain 75% is the operator

- Arab Petroleum Investment Corporation 12.5% today replaced by the Boubyan Petrochemical Company.

- Chevron ( through Caltex subsidiary) 12.5%

To process this associated gas, Banagas invested in first:

- Series of four compressors station

- Liquid petroleum gas (LPG) processing facilities

- Tank farm to store butane, propane, naphtha and other condensates.

In 1988, Banagas proceeded to the first expansion with the addition of a second LPG train to increase the capacity from 170 million cubic feet per day (cf/d) to 280 million (cf/d). This Banagas first expansion included two more compressors and one additional gas central processing plant.

Tatweer Bahrain Field Development boosts Banagas

In 2003 and in 2011, Banagas added new compression stations again to follow the Bahrain Field Development Project operated by Tatweer. Tatweer was formed to stop the depletion of the Bahrain field and initiate the Bahrain Field Development Project.




Using the last enhanced oil recovery (EOR) technologies, Tatweer has been drilling 900 new wells and proceeding to steam injection, water flooding with the ambition to triple the oil and gas production between 2011 and 2017 to reach:

- 100,000 barrels of oil per day (b/d)

- 2.0 billion cf/d of natural gas.

In order to follow the good implementation of the Tatweer Bahrain Field Development Project, Banagas is now working on the feasibility study to add a third processing train in Sitra to treat the corresponding associated gas. This Banagas Third Train should require an investment of $300 million capital expenditure.

In 2008, Banagas established a dedicated subsidiary called Bahrain National Gas Expansion Company (BNGEC) to managed and operate Banagas expansion projects. After treatment this gas is only

consumed locally, partly reinjected to support Tatweer EOR program, partly burnt in gas-fired power generation, and partly sold to the local aluminum industry.

Instead, most of the LPG are exported to the global markets.

To align the processing capacities on the associated gas generated by Tatweer Bahrain Field Development Project, Banagas should start the front end engineering and design (FEED) of this Bahrain third processing train in 2014 to award the engineering, procurement and construction (EPC) contract in 2015 with the first production due in 2017.

About Bahrain Oil & Gas :

• The Kingdom of Bahrain is, along with Oman, one of only two countries bordering the Gulf that is not a

member of the Organization of the Petroleum Exporting Countries. Bahrain produced 48,000 barrels

per day (bbl/d) of total petroleum liquids in 2012, the least of any country in the Gulf. It has set a goal

of increasing total petroleum production to 100,000 bbl/d by the end of the decade.

• Refinery capacity far exceeds domestic crude oil production capacity. Bahrain has a 254,000 bbl/d

export refinery at Sitra. Most of the feedstock is imported from Saudi Arabia, so that net exports for

Bahrain are only about 5,000 bbl/d. Plans are underway to expand the refinery's capacity by 100,000

bbl/d by 2017.

• Saudi Arabia and Bahrain share production of the 300,000 bbl/d Abu Safah offshore field in Saudi

Arabia, which is connected to Bahrain's Sitra refinery via pipeline. Bahrain intends to replace the aging

pipeline system from Saudi Arabia with the planned New Arabia pipeline, a 71-mile, 350,000 bbl/d

pipeline running between the Abqaiq complex in Saudi Arabia and Bahrain's refinery at Sitra.

• As with oil, the country is a small producer of natural gas, and produced 446 billion cubic feet of dry

natural gas in 2011. In order to meet future natural gas needs, Bahrain plans to import gas from a

number of sources, either via pipeline from Qatar or via imports of liquefied natural gas (LNG) following

the awarding of a contract to construct a new LNG terminal.

• Bahrain has over 3 gigawatts of electricity generating capacity, almost all of which is conventional

thermal fired. The Kingdom has recently begun to develop solar and other renewable power. It is also

taking part in the Gulf Cooperation Council's (GCC) plan to integrate the electric power grids of all GCC

countries.




Beijing’s LNG imports growing at record pace Reuters/Singapore

China’s imports of liquefied natural gas (LNG) are growing at a record pace as it aims to use cleaner fuels to cut smog in big cities, creating a powerful new source of demand that has the potential to reshape the market for the super-chilled gas.

Rising Chinese demand gives LNG producers such as Chevron , Royal Dutch Shell, ExxonMobil and Total a crucial new sales avenue as they weigh whether to go ahead with $180bn in investments into potential new or expanded LNG projects.

Producers face rising costs in Australia – where many LNG projects are based – and uncertainty about longer-term demand in Japan and South Korea, the world’s top two buyers of the fuel.

The Chinese, though, are spending billions of dollars in buying LNG-related interests overseas and in building new import terminals. LNG imports are up 35% to 5.62mn tonnes in the first quarter against the year-ago period, according to customs data.

And imports are set to rise by a third this year, according to research firm Energy Aspects. They grew 25% annually over the last four years, Thomson Reuters Point Carbon says.

“Producers are certainly looking at China, because that’s the only market right now that will offer 2-3mn tonnes deals,” said Gavin Thompson, head of Asia Pacific gas and power at consultancy Wood Mackenzie.




By the end of this decade, China could overtake South Korea to become the world’s second-biggest LNG buyer behind Japan.

The consultancy forecasts China’s imports to rise to 61mn tonnes in 2020 from 18mn tonnes last year, led by supply from Australia. By comparison, South Korea’s state-run Korea Gas Corp (KOGAS) expects demand to rise to 45mn tonnes by 2020 from 40mn last year. Japan and South Korea have increased LNG consumption to replace lost nuclear power, but uncertainty remains about the future of idled nuclear plants amid safety and cost concerns.

China’s state energy companies, meanwhile, are already competing for supply by securing equity stakes in projects across the globe. Malaysian state-owned oil firm Petronas said in April it will sell a 15% stake in its $11bn LNG export terminal on Canada’s Pacific Coast to China’s Sinopec Group and state-owned power group China Huadian Corp .

China plans to more than double its natural gas supply capacity to 400bn cubic metres per year by 2020. Still, uncertainty remains about the pace of growth in a country where energy use is dictated by politics. And consistently high LNG prices in Asia since the Fukushima disaster could hamper demand growth in China, as the country remains more price sensitive than Japan and South Korea.

Nevertheless, Asian prices are widely expected to fall as a new wave of Australian supply hits the market in the next 3-4 years, further boosting Chinese demand, industry observers say. China’s import needs also depend on how successful it is in developing its own unconventional gas resources. China, believed to hold the world’s largest reserves of shale gas, hopes to replicate the US production boom.

“Whether or not China develops its own natural gas production can make a huge swing in the global demand,” said David Carroll, vice president of the International Gas Union.

Until now, at least, it seems China’s state energy firms have focused mostly on securing gas from projects abroad and shipping it to a string of new LNG imports terminals. Import capacity is slated to rise from the current 31mn tonnes per year at nine terminals to over 80mn tonnes by 2018, when another 15 import terminals either approved or already under construction begin operations.

Add to that another 13 terminals that are either planned or proposed and capacity could top 110mn tonnes by the beginning of the next decade. By comparison, Japan last year imported 87mn tonnes of LNG.




Kenya/Ethiopia: Africa Oil provides operational

update and first quarter results .. Source: Africa Oil Corp

Africa Oil Corp has provided first quarter 2014 financial results and an update on its operations in Kenya and Ethiopia. The Company currently has six rigs operating in Kenya and Ethiopia which are focused on three main activities; 1) Drilling new basin opening wells; 2) Drilling new prospects in the discovered basin in Northern Kenya; and 3) appraising and testing existing discoveries.

Two basin opening wells are currently drilling with results expected in the second quarter of 2014. The Sala prospect, on Block 9, is being drilled in the Cretaceous Anza graben and will test a large anticlinal feature along the northern basin bounding fault. This well is operated by Africa Oil which holds a 50% interest and operatorship with partner Marathon Kenya holding the remaining 50%.

The other new basin opening well is the Shimela well being drilled in the Chew Bahir basin on the South Omo block in Ethiopia. This basin is located along the Tertiary rift trend and has many similarities to the recent discoveries in Kenya. The rig will move to the

Gardim prospect following the completion of Shimela which is a basin bounded fault prospect located in the southern portion of this basin. The Company holds a 30% working interest in this block along with operator Tullow Oil (50%) and partner Marathon Ethiopia (20%).

Plans are also underway to drill prospects in three additional new basins this year. The

Dyepa-1 well will spud in the second quarter and will target the South Kerio basin which is proximal and geologically similar to the discovered basin in Northern Kenya in Block 10BB. This well is designed to test a basin bounding fault prospect on the western flank of the basin similar to the string of pearls field discoveries such as the initial Ngamia discovery. A number of additional prospects have been identified in this basin which would be de-risked if Dyepa is a discovery. This rig will then move to test the Aze

prospect which is located in the North Kerio basin and is comprised of a large, four-way dip closed anticline on the southern shore of Lake Turkana.

The last basin to be targeted this year is the West Turkana basin in Block 10BA in Kenya and the first well in this program is expected to spud later this year. The first prospect to be drilled will be the Engomo




(formerly Kiboko) prospect on the western shore of Lake Turkana. It is also a basin bounding fault prospect and has similar potential to prove a petroleum system that would lead to accelerated drilling on a number of identified prospects. In both of these basins, as in the discovered basin in Northern Kenya, the Company holds a 50% working interest along with Operator Tullow Oil (50%).

The only well which is currently being drilled on a new prospect in the discovered basin in Northern Kenya is the Ekunyuk-1 well which is located on the eastern flank play, on trend with recent discoveries at Etuko and Ewoi. The well has now reached a final total depth of 1,802 meters and has encountered some 5 meters of net oil pay, within approx. 150 meters of reservoir quality water-bearing sandstone and an equal thickness of a basin-wide rich oil shale. This rig will now be moved to the Agete-2 location.

Three additional rigs are currently pursuing appraisal and testing activities on the existing discoveries. The Sakson PR5 rig is continuing drilling operations on the Twiga-2 up-dip appraisal well. The initial wellbore was drilled near the basin bounding fault and encountered some 18 meters of net oil pay within alluvial fan facies, with limited reservoir quality. A decision was made to sidetrack the well away from the fault to explore north of Twiga-1 and some 62 meters of vertical net oil pay has been discovered in the Auwerwer

formation, similar in quality to the initial Twiga-1 discovery. The well is currently being deepened to evaluate the Lower Lokhone sand reservoirs and a testing program for this successful well is planned to be conducted later this year. This rig will then move to drill a down-dip appraisal of the Amosing discovery, which appears to have high quality reservoir and may be one of the largest discoveries in the basin to date.

The PR Marriott 46 rig is currently drilling ahead on the Ngamia-2 appraisal well which is expected to be completed by the end of the second quarter. This rig will then drill the Ngamia-3 appraisal well.

Testing operations are ongoing on the Agete-

1 well using the SMP-5 rig and expected to be completed by the end of May. The plan is for this rig to continue testing operations on discovery and appraisal wells in the discovered basin in Northern Kenya.

Additionally in Ethiopia, the Company has recently completed the drilling of the El

Kuran-3 appraisal well on Block 8. El Kuran-3 was an appraisal of a discovery made by Tenneco in the 1970's, and encountered a significant but tight gas-

condensate zone in Jurassic Hammanlei carbonates. The well has been suspended pending a decision on conducting a fracture stimulation, which will be required to assess the long-term productivity of the formation. Discussions are ongoing with the Government of Ethiopia to secure an extension to the Exploration Period under the PSC to assess the economic viability of the discovery.




Africa Oil CEO Keith Hill stated: ‘Our goal is to open up at least one new basin and to move a significant number of barrels from prospective to contingent resources by the end of 2014 as we move the field development program forward.'

The Company is also actively pursuing development studies in the Block 10BB/13T area including commencement of the pre-front end engineering design (pre-FEED) and environmental and social impact assessment (ESIA) studies for the pipeline, export terminal and field facilities. It is the goal the Government of Kenya and the joint venture partnership to achieve project sanction, including the approval of an export pipeline, by the end of 2015/early 2016.

Further Significant Events During The First Quarter of 2014:

• Africa Oil ended the quarter with cash of $434.3 million and working capital of $360.1 million.

• In January, the Company announced a new oil discovery at Amosing-1 located seven kilometers southwest

of the Ngamia-1 discovery along the Basin Bounding Fault Play in Block 10BB. Logs indicated 160 to 200

meters of potential net oil pay in good quality sandstone reservoirs.

• In January, the Company announced a new oil discovery at Ewoi-1 located four kilometers to the east of the

Etuko-1 discovery in the Basin Flank Play on the eastern side of the discovered basin in Northern Kenya in

Block 10BB. Logs indicated potential net pay of 20 to 80 meters to be confirmed by well testing.

• In February, the Company announced the results of five well tests conducted on five Lokhone pay intervals

at Etuko-1 located on the Basin Flank Play in Block 10BB. Light 36 degree API waxy crude oil was successfully

flowed from three zones at a combined average rate of over 550 barrels of oil equivalent per day. In March,

the Company announced the results of the Etuko-2 exploration well drilled to test the upper Auwerwer

sands overlying the previously announced Etuko discovery. Etuko-2 penetrated a potential significant oil

column identified from formation pressure data and oil shows while drilling and in core, with good quality

reservoir but flowed only water on drill stem test. The results are considered inconclusive and analysis is

underway to consider further options to evaluate this reservoir.

• In March, the Company announced the results of a well test on the Ekales-1 discovery drilled in 2013 and

located on the Basin Bounding Fault Play between the Ngamia-1 and Twiga South-1 discoveries. Testing

operations on the Ekales-1 well confirmed this significant oil discovery. Two drill stem tests were completed

and flowed at a combined rate of over 1,000 bopd from a combined 41 meter net pay interval. The upper

zone had a very high productivity index of 4.3 stb/d/psi.

• In March, the Company announced the results of the Emong-1 well located four kilometers northwest of

Ngamia-1 field discovery in Block 13T (Kenya). The well encountered oil and gas shows while drilling,

however the Auwerwer sandstones that are the primary reservoirs in the Ngamia field were thin and poorly

developed in Emong-1 and the well was plugged and abandoned. It is believed that the reservoir was poorly

developed due to its proximity to the basin bounding fault and its location within what appears to be a local

isolated slumped fault margin. This well, which was trying to establish an additional play, has no impact on

the potential of the Ngamia oil accumulation or any other prospectivity in the discovered basin in Northern

Kenya.

• In Blocks 10BB and 13T, the acquisition of a 550 square kilometer 3D seismic program over the discoveries

and prospects along the Basin Bounding Fault Play in the discovered basin in Northern Kenya is ongoing and

is scheduled to complete at the end of the third quarter.

• In March, the Company completed a farmout transaction with Marathon whereby Marathon acquired a 50%

interest in the Rift Basin Area leaving the Company with a 50% working interest. In accordance with the

farmout agreement, Marathon was obligated to pay the Company $3.0 million in consideration of past

exploration expenditures, and has agreed to fund the Company's working interest share of future joint

venture expenditures to a maximum of $15.0 million with an effective date of June 30, 2012. Upon closing of

the farmout, Marathon paid the Company $3.0 million in consideration of past exploration expenditures.

Subsequent to the quarter end, Marathon paid the Company $10.2 million being Marathon's and the

Company's share of exploration expenditures from the effective date to the closing date of the farmout.




• In March, the Company completed a farmout transaction with New Age whereby New Age acquired an

additional 40% interest in the Company's Adigala Block leaving AOC with 10% working interest. In

accordance with the farmout agreement, New Age is obligated to fund the Company's 10% working interest

share of expenditures related to the acquisition of a planned 1,000 kilometer 2D seismic program to a

maximum expenditure of $10.0 million on a gross basis, following which the Company would be responsible

for its working interest share of expenditures.

• The Company has a significant exploration and appraisal program set out for 2014 which will see over 20

wells completed. The program is focused on drilling out the remaining prospect inventory in the discovered

basin in Northern Kenya, appraising existing and future discoveries with the aid of the new 3D Seismic

survey, drilling six new basin opening wells and progressing development studies towards project sanction in

the discovered basin in Northern Kenya. This significant program in 2014 is fully funded.

Outlook

The Company expects to have six drilling rigs operating through the remainder of 2014, one of which is currently being utilized as a testing and completion rig. Completion of the brokered private placement in October 2013 increased the Company's liquidity and capital resource position which is expected to fully fund the Company's portion of 2014 exploration, appraisal and development activities.

The near term focus of exploration is to continue drilling and testing wells in the discovered basin in Northern Kenya improving on recent cost efficiencies realized while continuing to grow the Company's contingent resource base, and to drill potential basin-opening wells in the Turkana, Chew Bahir, Kerio, and Anza basins within Kenya and Ethiopia.

Given the significant volumes discovered and the extensive exploration and appraisal program planned to fully assess the upside potential of the basin, the Tullow-Africa Oil joint venture has agreed with the Government of Kenya to commence development studies. In addition, the partnership is involved in a comprehensive pre-FEED study of the export pipeline. The current ambition of the Government of Kenya and the joint venture partnership is to reach project sanction for development, including an export pipeline, by the end of 2015 or early 2016. The Government is already making progress, having recently announced

its intention to invite Expressions of Interest for the feasibility study, engineering design and development of a Kenya crude export pipeline. If further exploration success opens additional basins there will be scope for the development to be expanded.

In 2014, the Company expects to drill six new basin opening wells, drill all key prospects in the discovered basin in Northern Kenya,

appraise existing discoveries, and progress development studies towards project sanction in the discovered basin in Northern Kenya.




U.S : Magnolia LNG Project Moves Forward Press Release, May 14, 2014; Image: Magnolia LNG

Liquefied Natural Gas Limited said that Merlin Advisors has been appointed as the Lenders’

Engineer for the company’s 8 million tonne per annum Magnolia LNG project development in Lake

Charles, Louisiana, United States.

Under the engagement Merlin’s scope of work will generally comprise 2 key phases:

Phase 1:

Review of the current status of the project, including the site, front end engineering design, material contract terms and development plans and schedule, to identify any issues which could potentially impact project delivery;

- Ongoing review of the project development to provide early identification of any potential bankability and project financing issues.

Phase 1 is a critical process as it will enable the company to work with BNP Paribas (the Project’s financial adviser and lead debt arranger) and Merlin to identify and address any potential issues, including those with financing implications, early in the project development process.




Phase 2:

- Detailed Bankability Due Diligence Report, which will be a key document in relation to the company’s Final Detailed Project Feasibility Study and the Project Information Memorandum to be issued to prospective project debt financiers, including major international banks and Export Credit Agencies.

The company’s Chief Financial Officer, Norman Marshall, said: “Merlin brings a wealth of LNG and energy industry experience to the Project. While Merlin will be working specifically on behalf of the Project lenders, both Phase 1 and Phase 2 will be very interactive processes, between BNP Paribas, Merlin and the Company, to assist the Company ensure the Project remains bankable.”

“We are now working closely with BNP Paribas on the engagement of the lenders’ legal counsel, which will also be a critical role to assist ensure all material Project contracts and agreements comply with international project financing requirements.”

Magnolia LNG, a newly formed, wholly-owned subsidiary

of Liquefied Natural Gas Limited (LNGL), is developing

an up to 8 million tonne per annum (mtpa) mid-scale

LNG facility in the Port of Lake Charles, Louisiana, USA

using LNG Limited's highly efficient and patented

OSMR® technology




Gasol to Buy 30 Pct in Malta Power & Gas Press Release,

Gasol announced that, as part of a consortium called ElectroGas Malta, it has entered in to a share

purchase agreement pursuant to which it will acquire a 30 per cent stake in Malta Power & Gas

Limited, a special purpose company established by Malta’s state power utility, Enemalta, to own and

operate the LNG-to-power project in Malta that was awarded to ElectroGas in late 2013.

MPGL has obtained the relevant development permits for the Project.

Pursuant to the SPA, the remainder of MPGL’s shares will be acquired by the other members of the ElectroGas consortium as follows: SOCAR Trading SA (20%), GEM Holdings Ltd (30%) and Siemens Projects Ventures, the equity financing arm of Siemens Financial Services (20%).

ElectroGas intends to rename MPGL “ElectroGas Malta Ltd.” prior to closing the financing for the project.

Commenting on the Project, Gasol

COO Alan Buxton, said: “This is a significant step in the development of the Project and we look forward

to the implementation phase.”




US to buy gasoline end-July or early Aug to build reserve —By Reuters

The United States aims to buy gasoline in end-July or early August to build emergency stocks to cover the hurricane season, using the $495 million from a strategic oil reserve test sale, the top U.S. energy official said on Tuesday.




U.S. Energy Secretary Ernest Moniz told Reuters in an interview that the first test sale from the nation's Strategic Petroleum Reserve since 1990 "went very well," and that half of the 5 million barrels of crude that was sold has been drawn. The U.S. Energy Department earlier this month unveiled a plan to create a million-barrel gasoline reserve in the Northeast, a reaction to the aftermath of Superstorm Sandy in 2012 when motorists were left without fuel, exposing vulnerabilities in the country's fuel distribution network.

"We want to get, of course, as much of the hurricane season covered as possible. So, we are looking at mid-summer to have it in place,'' Moniz said, identifying that as end-July or early August. Under the $200 million emergency reserve plan, two sites will each store 500,000 barrels of gasoline by late summer, one near New York Harbor and one in the New England region.

Moniz who was in Seoul this week for a conference added that once the precise sites have been chosen, detailed distribution plans will be studied. The U.S. energy department surprised oil markets in March when it said it would hold its first test sale of crude oil from the Strategic Petroleum Reserve since 1990.

Gerhard Roiss, CEO of OMV, discusses the impact of the Russian sanctions on European gas, and dismisses calls for a unified gas price across the region. The sale was held to help assess the




government's ability to transport oil from the reserve located in Louisiana and Texas to local refiners as the domestic shale oil boom has resulted in an upheaval in energy logistics.

"We had the sale to test the infrastructure because in an emergency we have to know that we are able to draw down. And the underlying issue is that with our new oil production and with it coming from different places, some of the infrastructures has changed,'' Moniz said. Asked if there was any discussion with Asian nations including South Korea over possible U.S. crude exports, Moniz said: "It was raised by our Korean colleagues, but (it was) not a very detailed discussion.''

The U.S. government currently prohibits exports of crude, with a few exceptions including to Canada, but it is considering allowing sales to overseas markets as domestic stockpiles hit record highs. On the possible crude exports, Moniz in a separate press briefing earlier on Tuesday cited the U.S. president's counselor John Podesta as saying the issue is under consideration.

"I want to remind you that we are still a major importer of oil. So, it is true that we are producing a lot more oil, and frankly we expect to be close to 10 million barrels per day in crude oil production within a few years.'' In the briefing he added that multiple agencies are studying possible crude exports but the commerce department has the final responsibility for the decision.

Asked if the United States plans to ask the International Energy Agency to make a release from its strategic reserves if Russian oil exports are disrupted, he told Reuters there was no plan at the moment."Right now, we don't see disruption in the oil market ... the markets have been very steady throughout the whole process,'' Moniz said.

Tensions over Russia's military intervention on Ukraine's Crimean peninsula and its aftermath in eastern Ukraine have been rattling oil markets for the last couple of months. Brent futures have been holding near $108 a barrel, slightly below a peak of $112.39 on March 3, the highest in more than five months.

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Khaled Malallah Al Awadi, MSc. & BSc. Mechanical Engineering (HON), USA ASME member since 1995 Emarat member since 1990

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Khaled Al Awadi is a UAE NatiKhaled Al Awadi is a UAE NatiKhaled Al Awadi is a UAE NatiKhaled Al Awadi is a UAE National with a total of 24 yearsonal with a total of 24 yearsonal with a total of 24 yearsonal 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 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 GCC area via Hawk Energy Service the GCC area via Hawk Energy Service the GCC area via Hawk Energy Service the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in 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 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 desigexperiences in the desigexperiences in the desigexperiences in the designing & constructingning & constructingning & constructingning & 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 with many MOUs for Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local the local the local the local

authoauthoauthoauthorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andrities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andrities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andrities. 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 satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satellite ChannelsChannelsChannelsChannels . . . .

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