New base 514 special 08 january 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 08 January 2015 - Issue No. 514 Khaled Al Awadi

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

Dubai : Solar Testing Facility at Mohammed Solar Park WAM + NewBase

Saeed Mohammed Al Tayer, MD and CEO of Dubai Electricity and Water Authority, DEWA has visited the construction site of the Solar Testing Facility at the Mohammed bin Rashid Al Maktoum Solar Park ( MRMSP ), which will be one of the largest Photovoltaic (PV) testing centres in the region. The testing facility is part of the Research and Development Centre at Solar Park.

Al Tayer, who was accompanied by Waleed Salman, Executive Vice President of Strategy and Business Development at DEWA, emphasised the importance of the solar testing facility, which includes two testing facilities, one for photovoltaic solar testing and the other for concentrated solar power (CSP).

Al Tayer said, "The Mohammed bin Rashid Al Maktoum Solar Park underlines DEWA’s commitment to achieve the vision of Vice President and Prime Minister and Ruler of Dubai, His Highness Sheikh Mohammed bin Rashid Al Maktoum, to diversify the energy mix in Dubai.

It supports the Green Economy for Sustainable Development initiative, which was launched by His Highness to enhance the sustainable development of Dubai." "The park is a key pillar in accomplishing the goals of the Dubai Integrated Energy Strategy 2030, developed by the Dubai Supreme Council of Energy to reduce energy demand and promote renewable energy sources.




As per the strategy, solar energy will constitute 5 percent of Dubai’s energy portfolio by 2030. It also support the Dubai Plan 2021 for Dubai to sustainably manage its resources, and ensure its environment is clean, healthy, and sustainable."

"H.H. Sheikh Hamdan bin Mohammed bin Rashid Al Maktoum, Crown Prince of Dubai and Chairman of the Dubai Executive Council, has issued Resolution No. 46 of 2014 regulating the linkage of solar power generation to Dubai's grid. It supports the smart initiative that DEWA has launched to encourage households and building owners to install photovoltaic solar panels to generate electricity.

The solar system provides electricity on site and the surplus is exported to DEWA’s network." Al Tayer noted that the DEWA R&D team is currently engaging in various international initiatives and projects across the world in solar energy.

"The centre will test solar cell technologies and PV panel technologies and manufacturing for greater flexibility. This centre will also assess other aspects to cope with various weather conditions and the surrounding environment both when PV panels are used in open spaces or integrated into buildings," said Waleed Salman.

The Testing Centre has several sections including a measurement room, control room, and offices.




Total teams up with Masdar to probe carbonate reserves Saudi Gazette + NewBase

TOTAL unveiled Wednesday a collaboration to map the complex behavior of the region’s carbonate reserves. The ‘Digital Rock Physics’ (DRP) project will pool the technical resources and expertise of the Masdar Institute, the world’s first graduate-level, research-driven university dedicated to providing innovative real-world solutions to issues of sustainability, and Abu Dhabi’s Petroleum Institute. It marks the first research and development collaboration between Total and the Abu Dhabi National Oil Company (ADNOC).

The aim of the project is to produce an extensive archive of rock images in microscopic detail, as well as to digitally simulate and test the behavior of oil and gas reservoirs with a view to maximizing oil recovery. Masdar Institute’s state-of-the-art microscopy facility will be used to examine rock samples at the nano-scale to generate 3D images of the pore network and pore morphology of typical Abu Dhabi reservoir rock cores. With an initial staff of four Total researchers, the project has been designed as an ‘open laboratory’ to encourage knowledge transfer through the acquisition and analysis of rock data from all over the world.

Stéphane Michel (right), Total’s Middle East & North Africa

president for Exploration & Production, during his visit to the

new regional headquarters of SunPower Corporation – Total’s

solar power affiliate – located at Masdar City




The collaboration announcement was made as a Total delegation toured Masdar City, accompanied by Dr. Ahmad Belhoul, CEO of Masdar, Abu Dhabi’s renewable energy company, and senior management from Masdar and Masdar Institute. During the tour, Stéphane Michel, Total’s Middle East & North Africa (MENA) president for Exploration & Production, visited the new regional headquarters of SunPower Corporation, Total’s solar power affiliate. The opening of the office – located at Masdar City, Abu Dhabi’s low-carbon, sustainable development – will enable SunPower to manage existing developments and pursue new solar energy projects across the MENA region. SunPower has been active for more than a decade in the region, where it is associated with a number of flagship renewable energy projects. Located inside the Incubator Building, SunPower’s regional base reinforces the company’s longstanding association with Masdar. “The addition of SunPower to Masdar’s innovation ecosystem is another important benchmark as Masdar City grows and integrates a diverse mix of technology tenants,” said Dr. Belhoul. “The DRP project underlines our ability to facilitate public-private partnerships to accelerate the development of innovative technological solutions that enhance the UAE’s energy sector.” “Total is immensely proud of its 75-year history in Abu Dhabi, and our collaboration with Masdar, and other Abu Dhabi partners, reflects the strength of our investment in the future of energy, in the emirate and the region,” said Stéphane Michel of Total. “Both the DRP project and the opening of a new regional base for SunPower are tangible evidence of Abu Dhabi’s potential to help advance the responsible development of conventional energies, and the contribution of new energies to meeting increasing power demand.”




Qatar well-placed to weather energy market pressures By Denise Marray/Gulf Times + NewBase

“Qatar has become the most significant and consistent supplier of LNG to the UK, whose gas position has shifted from one of self sufficiency in 2004 to one of 50% import requirement by 2014, due to the inevitable decline of UK North Sea gas production.

” This observation was made by Howard Rogers, director, Natural Gas Research Programme, Oxford Institute for Energy Studies, in response to a question from Gulf Times about the relationship between Qatar and the UK in terms of energy provision.

He added: “Although the UK receives significant pipeline gas supplies from Norway, the Netherlands and continental Europe in general, longer term domestic production decline will inevitably mean that the UK will need an ever higher percentage of imports — either of pipeline gas from the continent (backed up by Russian gas) or LNG.

He was asked for his views on the likely impact on Qatar of recent developments in the US energy sector. He observed: “The US currently has LNG export projects amounting to between 70 and 90 bcma under construction or about to commence construction. This is likely to become a major source of destination-flexible LNG, able to arbitrage between Asian, European and South American markets.

“Unless upstream supplies of shale gas are constrained due to resource availability or pipeline bottlenecks, the US may well displace Qatar as the primary ‘destination swing supplier’. In this case, it is likely that Qatar will increasingly target Asian markets due to its transportation cost advantage relative to US LNG.”




Rogers was asked to comment on the role of Russia and its impact on Qatar. He replied: “If Qatar keeps in place the North Field Moratorium and, therefore, does not expand its LNG exports, this is more a case of how Qatar can best maximise its LNG revenues in the context of the overall fundamentals of the global gas system connected by LNG trade flows.

“Russia, with some 100 bcma of ‘spare’ production, and the largest exporter of pipeline gas, has a major role to play in this. In Europe, it may choose to defend market share (at the expense of price) to try and keep LNG out of this ‘market of last resort’, or reduce exports to defend price.

“In Asia, the proposed pipeline projects to China seem at first glance a significant ‘win’ for Russia; but, all other things being equal, they reduce Chinese LNG requirements, and thus increase LNG available for Europe, at the expense of Russian exports to Europe. Qatar will play into these dynamics with the aim of maximising revenues in a much more competitive environment than we have seen in the last three years.”

Asked about the importance of coal in the energy mix, he noted that “without concerted policy commitment, it is difficult to see how gas at sustainable prices can displace coal in power generation purely on a competitive fuel price basis.”

He added: “Coal in power generation is the primary source of anthropomorphic CO2 emissions. Its cost advantage over gas at current prices has made it difficult to displace in Asian markets in particular, but also in Europe, despite that region’s apparent commitment to CO2 emission reduction.”




Looking at how Qatar has managed its energy policy, he said that the country had been prudent in carefully planning the placement of its LNG output over a wide geographical spread and through differing contract/price formation channels.

“Volumes were placed under long term crude oil price indexed contracts with Asian buyers, through oil and oil product — linked priced long term contracts with Southern European buyers, and via medium term contracts and regas-infrastructure investment enabled spot delivery to US and Northern European buyers.

From the outset it was clear that volumes of LNG which were not subject to long term contracts could be redirected and sold as spot or under short term deals under a dynamically managed sales strategy,” he noted.

With regard to the medium and long terms prospects for Qatar, he said: “In a medium term period of muted demand growth, Qatar’s major concern should be the 85 bcma of new supply from Australian LNG projects coming onstream between 2015 and 2018, and the start of US LNG exports in 4Q 2015 but growing materially from 2018 onwards.

Towards the end of the decade Russia, East Africa, Canada and new brown-field Australian projects may add volumes in a soft market. In simplistic volume terms, Australia, by dint of projects already under construction, will overtake Qatar to become the largest LNG supplier before 2020.”

Looking at the volatility in oil prices, he concluded: “The timescale for recovery of oil prices in the current price crash is uncertain, but Qatar with its low population and strong financial position is well placed to weather the storm.”




Turkey: Canada's Valeura Energy Flows Gas from Turkish Well VE Inc + NewBase

Valeura Energy has announced gas flow from Gurgen-2 appraisal well in the Thrace Basin of Turkey. The company on Tuesday said that the well has come on stream and producing at an average restricted rate of 3.0 million cubic feet per day (MMcf/d).

Canada based Valeura also plans a capital budget of up to $19 to 22 million (net) in Turkey in 2015 that is targeted to grow production volumes by 10 to 15 percent compared with 2014 and is expected to include the acquisition of approx. 140 sq kms of 3D seismic and drilling of up to three exploration wells on its 100% Banarli licence in the Thrace Basin. The company has made three conventional natural gas discoveries in the Osmanli area in the third quarter of 2014. The Gurgen-1 discovery well was the most productive of the three discovery wells and has been on-stream for 62 days at an average restricted rate of 3.1 MMcf/d.

Gurgen-2, the first of two planned appraisal wells on the Gurgen discovery, was spudded on November 30 and was drilled in 14 days to a vertical depth of 2,000 metres into the Osmancik formation. The well is tied-in and has been on-stream for 13 days at an average restricted rate of 3.0 MMcf/d.

The second appraisal well, Gurgen-3, was spudded on January 3, 2015. The well location is approximately 500 metres southeast of Gurgen-2.




Bangladesh: Santos-Kris Energy JV Initiates Seismic Survey Offshore FEB + NewBase

Santos and Kris Energy have initiated two-dimensional (2D) seismic survey this week in Block SS-11 offshore Bangladesh, according to Financial Express Bangladesh. The exercise will be carried out on behalf of the joint venture by French firm CGG at a cost of around $ 9.76 million, the newspaper stated citing sources.

The shallow water Block - SS-11 - is highly potential, as it is close to Myanmar's territorial water, where the neighbouring country discovered huge natural gas reserves. The block covers an area of 4,475 sq km in the Bay of Bengal. The majority of the block lies in shallow waters up to 200 meters with the furthest southwest portion extending into water depths up to 1,500 meters. Kris Energy holds a 45% non-operated working interest in the exploration block. Santos is the operator with 45% and Bangladesh Petroleum Exploration & Production Company Limited (BAPEX) holds 10%. According to Financial Express Santos-Kris JV has committed to drill an exploration well, conduct 1,876 line kilometer 2D seismic survey and 300 sq km 3D survey, and offered a bank guarantee of $15 million, for the initial five years of exploration. The JV bidder would require investing around $30-32 million to carry out its work plan under the production sharing contract (PSC) during the initial years. The contract period for exploration will be eight years in total. The contractor will be allowed to operate and sell oil and gas for 20 years from an oil-field and 25 years from a gas-field.







Oil Price Drop Special Coverage

Oil analysts balk at calling floor Bloomberg + NewBase

Oil’s drop has been so rapid and so driven by sentiment that forecasters from Bank of America Corp to UBS say there are no clear signs for when the rout will end. Brent crude slumped below $50 a barrel yesterday, 57% less than the peak of $115.71 reached in June. UBS analysts say investors should avoid oil until the “free fall” ends. Traders are ignoring supply disruptions that would normally boost prices, ABN Amro Bank analysts said. “It’s pointless to speak about the point of reversal,” Eugen Weinberg, head of commodities research at Commerzbank AG in Frankfurt, wrote in an e-mail on Monday. “It’s unpredictable and fundamentally not identifiable,” with prices now driven by sentiment rather than supply and demand, he wrote. Oil’s slump accelerated after the Organisation of Petroleum Exporting Countries said on November 27 it would maintain production. The 12-nation group is seeking to protect market share rather than prices, challenging US shale drillers and other rivals to pare their output instead. “The price drop has been too fast and too far for the fundamentals,” Hans van Cleef, an energy economist at ABN Amro in Amsterdam, said by phone on Tuesday. “The market is only focusing on the negative. It’s very hard to see a trigger which could turn the sentiment.” The market is “obsessed” with the perception of a supply glut and traders are ignoring disruptions such as those caused by fighting in Libya, Van Cleef said. A crude tanker was bombed there on January 4 while storage tanks at its biggest oil port were blown up last month. Libya has Africa’s biggest oil reserves. “Prices remain in a free fall,” Giovanni Staunovo, an analyst at UBS in Zurich, wrote in a report yesterday. “We think it is too early to call for a solid short-term price floor.” There is no evidence yet that non-Opec supply is contracting or that lower prices are spurring demand, both of which could halt the collapse, Miswin Mahesh, an analyst at Barclays Plc in London, said by phone yesterday. There is a “growing risk” that Brent will fall to $40 and West Texas Intermediate, the US benchmark, below $35, Francisco Blanch, head of commodities research at Bank of America in New York, wrote in a report yesterday. WTI closed at $47.93 on Tuesday in New York.




Oilfield writedowns loom as crude slump guts drilling values Bloomberg News + NewBase

Tumbling crude prices will trigger a flood of oilfield writedowns starting this month after industry returns slumped to a 16-year low, calling into question half a decade of exploration.

With crude prices down more than 50 per cent from their 2014 peak, fields as far-flung as Kazakhstan and Australia are no longer worth pumping, said a team of Citigroup analysts led by Alastair Syme. Companies on the hook for risky, high-cost projects that don’t make sense in a $48-a-barrel market include international titans such as Royal Dutch Shell and small wildcatters like Sanchez Energy Corp.

The impending writedowns represent the latest blow to an industry rocked by a combination of faltering demand growth and booming supplies from North American shale fields. The downturn threatens to wipe out more than $1.6 trillion in earnings for producing companies and nations this year. Oil explorers already are canceling drilling plans and laying off crews to conserve cash needed to cover dividend checks to investors and pay back debts.

“The mid-cap and small-cap operators are going to be hardest hit because this is all driven by their cost to produce,” said Gianna Bern, founder of Brookshire Advisory and Research, who also teaches international finance at the University of Notre Dame.

All of the 43 US oil and gas companies in the Standard & Poor’s energy index declined as of 4.37pm in New York, bringing the combined loss for the group to 23 per cent since crude began its descent from last year’s intraday high of $107.73 a barrel on June 20.

Oil dipped to $47.55 a barrel in New York, the lowest since April 2009. The decline represents a $4.4 billion drop in daily revenue for oil producers, which equates to $1.6 trillion on an annualized basis, Citigroup researchers led by Edward Morse said in a January 4 note to clients.




The oil-market rout is exposing projects dating as far back as 2009 that were either poorly executed or bad ideas to begin with, Syme’s team said in a note to clients. Shell, Europe’s largest energy producer, may have as much as 5 per cent of its capital tied up in money-losing projects. For UK-based BG Group, the figure could be as high as 8 per cent, according to the Citi analysts.

The biggest swath of asset writedowns probably will happen among so-called exploration and production companies, or E&Ps, a group that includes Sanchez, Matador Resources and Clayton Williams Energy, Bern said. That universe of explorers doesn’t have the same financial might as bigger producers such as Marathon Oil Corp, Bern said.

Houston-based Sanchez fell 12 per cent on January 5 in New York trading, bringing its one-year decline to 66 per cent. Clayton Williams, based in Midland, Texas, declined by 7.8 per cent.

Matador, which lost 8.5 per cent of its value yesterday, said today it will halt drilling in the Eagle Ford shale formation in south Texas and postpone its annual analyst presentation to February 5 from January 15 to allow more time to evaluate capital spending plans. “Impairments are unavoidable,” said Mark Sadeghian, an energy-industry analyst at Fitch Ratings in Chicago.

The writedowns that occur will be in the form of asset impairment charges related to the declining worth of specific oilfields, rather than wholesale reductions in proved reserves, Mr Sadeghian said. Investors are less inclined to punish oil companies for impairment charges than they would for a drop in reserve volumes, said Gabriele Sorbara, an analyst at Topeka Capital Markets in New York.

Citi expects Brent crude, an international crude benchmark, to average $62 this year, cutting earnings per share for major oil companies by an average of 29 per cent through 2017 and increasing pressure to postpone some drilling.

For the biggest US and European petroleum producers, return on equity - a measure of how profitably earnings are reinvested - has fallen to an average of 7.5 per cent, the lowest since the fourth quarter of 1998, according to Syme’s team. That’s triggering a cascade of spending cuts from Dallas to London that could boost return-on-equity for the group to an average of 11.5 per cent within three years, Syme’s group said.





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Khaled Malallah Al Awadi, Energy Consultant MS & BS Mechanical Engineering (HON), USA Emarat member since 1990 ASME member since 1995 Hawk Energy member 2010

Mobile : +97150-4822502 [email protected] [email protected]

Khaled Al Awadi is a UAE National with a total of 25 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed great

experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally , via GCC leading satellite Channels.




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

NewBase 08 January 2015 K. Al Awadi




Economy & Finance

New base 514 special 08 january 2014