New base 582 special 14 april 2015

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NewBase 14 April 2015 - Issue No. 582 Khaled Al Awadi

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

Total Pulls Out Of Oman Offshore Exploration Block 41 Reuters + NewBase

French oil and gas giant Total has pulled out of a deepwater block41 in offshore Oman after failing to make commercially attractive discoveries, a senior Omani official told reporters on Monday. Nasser Al Aufi, undersecretary at the Ministry of Oil and Gas, did not provide details regarding Total’s decision.

The company signed an exploration and production-sharing agreement in December 2013 for Block 41, which lies off the Omani coast northwest of Muscat and covers almost

24,000 square kilometres of seabed with depths of up to 3,000 metres. Aufi also said that last year Hungarian oil group MOL had pulled out from Block 34, and Norwegian oil firm DNO from Block 31.




Oman’s PDO Says To Increase Oil Output 5% In Four Years Reuters + NewBase

Petroleum Development Oman (PDO), the country’s top oil and gas producer, aims to lift crude output by about five per cent over the next four years, managing director Raoul Restucci said on Monday.

“We aspire to reach 600,000 barrels per day by 2019,” he told reporters at an annual briefing on Oman’s energy industry, adding the company would then maintain that production level for 10 years.

PDO’s planned average output for this year is 570,000 bpd, although it exceeded that amount in the first two months of the year, Restucci said in March. He said on Monday that PDO planned to invest over $40 billion in its projects by 2019, but did not specify where the company would obtain the money.

PDO is owned 60 per cent by Oman’s government, 34 per cent by Royal Dutch Shell, four per cent by Total and two per cent by Portugal’s Partex, according to its website. Salim Nasser al-Aufi, undersecretary at the Ministry of Oil and Gas, told the same briefing that government spending on Oman’s oil sector totalled $8.7 billion last year while spending on natural gas production was $2.8 billion.

Oman lacks the ample oil and financial reserves of its wealthy Gulf neighbours and its state budget has been hit hard by the decline of oil prices. But it is spending heavily to upgrade its energy industry infrastructure and boost production. Oman hopes to increase its total crude oil output by five per cent to one million bpd this year, Aufi said last month.

Issam al-Zadjali, chief executive of state-owned energy investment firm Oman Oil Co (OOC), said on Monday

that OOC would refocus more of its investments inside the country. Sixty-five percent of the company’s current investments are local; its investments in Europe are doing well but not those in India and China, Zadjali added.

OOC and its partners had invested a total of OMR9.4 billion ($24.4 billion) in companies within Oman as of 2013, according to its latest annual report. State-owned Oman Oil Refineries and Petroleum Industries Co (ORPIC) suffered a loss of $4 million last year, instead of the $725 million profit for which it was aiming, Chief Executive Musab al-Mahrouqi told the briefing.

Changes in the market environment as oil prices plunged cost the company $571 million, while technical problems at ORPIC’s Sohar refinery cut operations at its main refining unit by 76 per cent, costing a further $111 million.




Oman produces 943,000 bpd in 2014

Oman produced 943,000 barrels a day of oil and condensate combined in 2014, just missing its target of 950,000 barrels a day, Oman’s Undersecretary of Oil and Gas said in Muscat on Monday.

“Because of some problems we faced in the year, because of the condensate, we haven’t been able to produce all the amounts we expected,” Undersecretary Salim Nasser Said Al Aufi told reporters at the ministry’s annual media briefing.

Al Aufi did not state what the problems were.

The 943,000 barrels a day produced last year is in line with Oman’s annual production target of around 950,000 barrels a day since 2007 when the country produced 710,000 barrels a day. Al Aufi said Oman will continue to target 950,000 barrels a day but expects production to reach 980,000 barrels a day in 2015.

Oman is the largest Middle Eastern oil producer that is not a member of the Organisation of Petroleum Exporting Countries (Opec), whose members pump a third of the world’s oil, according to the US Energy Information Administration.

Oman added around 393 million barrels of oil to its general reserve in 2014, compared to 517 million barrels a year earlier, lifting oil reserves to 5.306 billion barrels as of December 31, 2014, Al Aufi said.

Oman invested $11.5 billion (Dh42.2 billion) into its oil and gas sector in 2014, a year when crude prices collapsed. Brent crude, the international marker for crude oil, fell from a June 2014 high of around $115 to $45 in January 2015. On Monday, Brent was trading at $58.96 a barrel, up 1.88 per cent at 2pm local time.

The majority of oil and gas investments were in the oil sector, accounting for $8.7 billion spent while $2.8 billion was invested into the gas sector. The majority of expenditures were for new projects, Al Aufi said, while 30 to 35 per cent of investment was to maintain existing operations.




Saudi Arabi: Lukoil likely to pull out of Saudi Reuters + NeBase Lukoil will likely pull out from Saudi Arabia where the economics of its search for gas have been crushed by the collapse of the oil price, three industry sources said. Lukoil is Russia's largest private oil company. The Russian energy industry's ventures abroad often parallel Kremlin foreign policy, which has turned cooler towards Saudi Arabia.

Some in Moscow blame Riyadh for allowing the oil price drop, which has hobbled Russia's economy, by not cutting output. Lukoil was the last company left active in the consortia of international oil firms Saudi Arabia invited in 2003-2004, part of a high profile drive to find gas in its southeast Empty Quarter, the Rub al Khali. It has a majority stake in Luksar - a joint venture with state oil company Saudi Aramco - which was set to drill deep for the unconventional gas, called tight gas, this year after more than a decade-long hunt for conventional deposits that has proved futile. Luksar was winding down, an industry source said. "By June, six or seven people will be there, so this is not a company anymore," the source said. "There are so many economic issues, it is uneconomic, with the low oil prices, the deep targets, it is expensive." A Lukoil source said the exit was likely. "There is no chance to get a reasonable price for gas from the Saudi government now when oil is so cheap," he said. Saudi Aramco has said it plans to cut costs and renegotiate contracts as a result of the lower oil prices. The slump in oil prices since June is testing the ability of listed oil companies to support cash flows and has sparked a rush to cut costs across the sector. None of the other companies, with the exception of Royal Dutch Shell, have said publicly they have pulled out from the Empty Quarter. But China's Sinopec, Italy's Eni and Spain's Repsol have

Deep exploration drilling on

Tukhman structure, Contract area

Block A in the Kingdom of Saudi

Arabia




all abandoned the search because of the relatively high cost and low returns of developing gas in Saudi Arabia, where sales prices are fixed at a fraction of probable production costs. "It wasn't a good prospect to begin with, the economic outlook has changed globally, it was always a high risk development," said Sadad al-Husseini, a former senior executive of Saudi Aramco and now an energy consultant. A third industry source said Lukoil was evaluating its options in Saudi Arabia and that there was no final definitive decision taken. Talks with Saudi officials were still ongoing but the company was "close to taking a decision... if there is no movement on improving the economics of the project." Saudi Aramco declined to comment. Saudi Arabia wants natural gas to help it cover subsidised domestic power demand so it can save its oil for more lucrative exports. Lukoil had decided to carry out trial work costing around $300 million in the Empty Quarter involving drilling one vertical and two horizontal wells which will take about two years, chief executive officer Vagit Alekperov said in a Lukoil publication on January 31. Alekperov said he was assured the gas price could be flexible for an individual project so its economics are attractive for the investor. Lukoil, Russia's second-largest oil producer said in March its net income fell by 39 percent last year to $4.75 billion, missing analysts expectations, due to weaker oil prices and non-cash impairment losses. Block A – Saudi Arabia – Luk Oil

In March 2004, LUKOIL Overseas joined the Block A exploration and development project. The term of the contract is 40 years. A joint venture was created to execute the project, LUKOIL Saudi Arabia Energy Ltd (LUKSAR), where LUKOIL Overseas owns 80% and 20% is owned by state oil

company Saudi Aramco. LUKSAR opened an office in Al Khobar (Eastern Province) in summer 2004.

Block A covers 29,900 square kilometers and is located in the Rub Al Khali desert in the southern part of Saudi Arabia near Al Ghawar, the world’s largest oil field. Exploration activities led to the discovery of a formation in the central part in the Tukhman structure containing 85 million tons of oil equivalent, as well as the Mushaib gas condensate formation containing 150 million tons of oil equivalent. A total of 9 exploration wells were drilled in the block during the exploration period. With the discovered fields entering the appraisal stage, 90% of the Block A territory was returned to the state fund. The total area to be appraised in the Tukhman and Mushaib fields is currently 2,900 square kilometers. The appraisal plan until mid-2016 includes 3D seismic covering an area of 1,700 square kilometers and drilling sidetracks from existing prospect wells. To date, an appraisal well has been drilled in the Tukhman field, and a research project is ongoing to study the best tight gas production techniques for the Mushaib field. Sidetracks from two existing prospect wells are planned in 2015 to update reserves and test production flow rates for the field.




Downstream focus may help GCC refineries’ capacity rise to 7.4mn bpd by 2022: S&P

Gulf Times + NewBase

The total capacity of GCC refineries may reach approximately 7.4mn barrels per day (bpd) by 2022 as Gulf producers reorient their focus on downstream projects in view of a decline in oil and gas prices, a new report has shown. The dip in oil and gas prices has encouraged Gulf producers to reorient their focus on downstream projects, rather than curb spending altogether, said Standard & Poors in a report. Gulf States are expanding their refineries to develop a downstream industry and export more value-added products, diversify away from oil and gas income, and meet rising domestic needs for fuel, it said. Currently, Gulf refineries’ total capacity stands at 4.3mn bpd, S&P said, quoting consultants Frost & Sullivan. S&P thinks that in certain jurisdictions the oil price decline could lead to an increased focus on renewables and other means of securing energy supplies that are less dependent on the cyclicality and volatility of oil prices.

An example would be the fiscal pressures Gulf sovereigns are facing as a result of recent commodity price declines, and the consequent potential for energy subsidy reform that could pave the way for more renewable projects in Gulf Cooperation Council (GCC) markets. Historically, S&P said, power plants using subsidised fossil fuels have had an economic advantage over renewable projects, typically wind or solar. However, lower government revenues stemming from cheaper oil and natural gas have prompted some administrations to rethink their energy subsidies. Oman, Qatar, and Bahrain have all raised the price of gas supplied to downstream industries. And any change in energy subsidies to the power sector that paved the way for more cost-




reflective tariffs will, in its view, improve the regulatory environment for renewable power projects in the region. “Despite the pressure of low oil prices, many governments have a commitment to use project finance as an effective tool to meet essential infrastructure needs, both within and outside of the oil and gas industry. They take the long term view and have not allowed the recent price drop to influence capital spending. “Saudi Arabia, Kuwait, and the UAE have all announced limited changes to their capital budgeting plans for 2015-2016, despite low oil prices.” The commodity price dip has also encouraged Gulf producers to explore shale opportunities. Speaking at an investment conference in Riyadh in January 2015, Khalid A al-Falih, chief executive officer of Aramco, said publicly for the first time that the company had already earmarked $3bn for shale gas exploration. Historically, investment in shale projects has required high oil prices because of the significant development costs associated with the exploratory phase, S&P pointed out. However, countries which built up fiscal reserves when oil prices were high, like Saudi Arabia, have a compelling reason for a presence in the shale sector, especially given recent technological advances in extracting oil and gas from shale. Market estimates put Saudi Arabian shale gas reserves at about 600tn cubic feet, and according to S&P, Saudi Aramco was in talks to secure 40 extra rigs to cover shale gas operations,indicating that it expected “large-scale production over the medium term.” Because of lower prices, however, some Middle Eastern and African countries have revised the subsidies they bring to certain projects. This, in turn, has elevated the importance of cost-reflective tariff arrangements and market-based pricing. “We think this will pave the way for more private-sector participation in some emerging markets in the utilities sector, particularly by way of participation through PPPs in competing generation plants.”




Indonesia: Pertamina, Kalla Group Agree to Build 4 Mtpa LNG Receiving Terminal

State owned energy firm Pertamina and Bumi Sarana Migas have agreed to build Indonesia’s second land based LNG receiving terminal, news agency Reuters reported Monday. Bumi Sarana Migas, a part of Kalla Group, and Pertamina have inked initial agreement to develop the 4 million-tonne-per-year (MTPA) project. Construction of the Bojonegara receiving terminal in Banten, Java should be complete by 2019, Pertamina CEO Dwi Soetjipto said in a statement without giving details about when work would commence, Reuters reported. "Infrastructure is the main requirement in utilizing gas fuel, because once infrastructure is installed demand will be created," Soetjipto said, noting that a power plant was expected to be built afterward using gas from the terminal to feed into the western Java grid.

According to Reuters, the two firms have already completed pre-feasibility studies for the project, with Pertamina expected to utilise 100 percent of the regasification facility for 20 years.




Shell Eyeing Onshore Gas Projects in Nigeria The Guardian Nigeria + NewBase

Shell has started the process of reviewing some large gas projects onshore Nigeria, according to The Guardian Nigeria newspaper.

This move is aimed at increasing company’s contribution to the nation’s LNG output, said Vice President, Nigeria and Gabon, Shell Upstream International, Markus Droll adding that negotiations have started with Nigerian National Petroleum Corporation (NNPC) and the Nigerian Liquefied Natural Gas (NLNG).

“Onshore, we are reviewing a number of large gas projects. If funding solutions are agreed upon, and when completed, these projects are expected to keep NLNG supplied with gas and to contribute to Nigeria maintaining its strategic position in the global LNG market,” Droll said in a paper titled ‘The Journey Towards Transformation’, The Guardian Nigeria reported.

He also stated that the company is committed to making the Assa North/Ohaji South project a reality. “This would be one of the largest domestic gas projects in Nigeria,” Droll said.




Senegal:FAR provides evaluation plan for Cairn-operated Source: FAR

Following the successful drilling campaign offshore Senegal in 2014, FAR Ltdand its joint venture partnersConocoPhillips, Cairn Energy and Petrosen (the Government of Senegal) are planning a first phase work program to evaluate the SNE-1 and FAN-1 discoveries. The work

program includes two wells to appraise the SNE-1 discovery and one exploration well likely to assess a 'shelf' prospect. The program will also include further evaluation of the FAN-1 discovery and a new 3D seismic survey over a part of the Contract area including a portion of the Sangomar and Rufisque blocks. An evaluation work program will be submitted to the Government of Senegal in May 2015. The SNE-1 and FAN-1 wells (shown in Figure 1) were the first exploration wells to be drilled in the deep water offshore Senegal and were the first to be drilled offshore Senegal for 26 years. As a result, these two wells were highly significant not only because they discovered oil but because they have provided key data to

update pre-drill geological models and have given FAR strong encouragement that further exploration drilling could result in more discoveries. To this end, and since the Notice of Discoveries was submitted to the Government in November 2014, the joint venture has progressed detailed analysis of SNE-1 and FAN-1 well data, extensive geological studies and modern 3D seismic reprocessing. FAR has re-assessed its portfolio of exploration leads and prospects based on the current data and these are included in this report.

Based on the size of the SNE-1 oil accumulation (gross, best estimate contingent resource 330 mmbbls*), excellent reservoir properties, known oil and gas column height and confidence in the mapping of the structure on 3D seismic data, SNE is the more attractive discovery for early evaluation and will be the initial focus of the joint venture’s evaluation work program. Cairn, the Operator, anticipates that two appraisal wells will be drilled and the reservoir will be flow tested




and cored in the first phase evaluation program. The objective of appraisal drilling is to confirm the reserves and productivity required for a commercial development (reference Cairn Preliminary Results Announcement to the London Stock Exchange, 10 March 2015). The minimum economic field size for a standalone development is estimated by Cairn, the Operator, to be approx. 200 million barrels (reference Cairn Preliminary Results Announcement to the London Stock Exchange, 10 March 2015).

Exploration wells are expected to focus initially on shelf prospects. Such prospects have the potential to contribute to building a larger resource base for an initial development project. The Operator estimates the minimum economic volume for a tie back development to be approx. 75 million barrels within a 25 km radius (reference Cairn Preliminary Results Announcement to the London Stock Exchange, 10 March 2015).

The development concept outlined by Operator for a SNE field development consists of a standalone Floating Production Storage and Offloading (FPSO) facility hub with potential to integrate nearby discoveries as shown in Figure 2. Gas re-injection and/or water flood is also contemplated (reference Cairn Preliminary Results Announcement to the London Stock Exchange, 10 March 2015).

FAR has reworked the mapping of the prospects and leads on the shelf following the FAN-1 and SNE-1 discoveries. The additional prospects mapped by FAR are shown in Table 1. Following the discovery of oil in the SNE-1 well FAR assesses the probability of success of encountering hydrocarbons for the shelf prospects to range from 33% to 52%.

Cairn, the Operator, continues work on finding an appropriate rig for the evaluation program. As stated at a recent RBC Investor Lunch Series in London, the Operator said that with falling deep water rig rates and the experience gained drilling offshore Senegal in 2014, they believe wells could be drilled offshore Senegal at US$30-40 million per well (taking 30-40 days per well). Based on this information, FAR estimates that the firm drilling program will cost approx. US$150 million with FAR’s share being approx. US$25 million (approx. AUD$33 million).




Statoil hits gas in Roald Rygg prospect (Norway) Source: Statoil

Operator Statoil has together with PL602 partners made a gas discovery in the Roald Rygg prospect in the Norwegian Sea. This is the second discovery made by Statoil in the Aasta Hansteen area spring 2015. The drilling of the Roald Rygg well 6706/12-3started on March 22, 2015 with a Transocean Spitsbergen drilling rig.“Statoil has completed a targeted two well exploration programme around

Aasta Hansteen which aimed to test additional potential in the area and make the Aasta Hansteen project more robust.

“Both wells, Snefrid Nord and Roald Rygg, have resulted in interesting discoveries, which will now be further evaluated for future tie-in to the Aasta

Hansteen infrastructure,” says Irene

Rummelhoff, senior vice president exploration Norway in Statoil.

According to Statoil, the well 6706/12-3, drilled by the Transocean Spitsbergen rig in the Roald Rygg prospect, proved a 38-metre gas column in the Nise Formation with very good reservoir quality. Statoil estimates the volumes in Roald Rygg to be in the range of 12-44 million barrels of recoverable oil equivalent (o.e.)

Roald Rygg is located less than 7 kilometres west of the Snefrid Nord discovery. The estimated total volumes in the two discoveries correspond to about 25% of the Aasta Hansteen recoverable volumes.

According to the company, Aasta Hansteen will be the largest SPAR platform in the world and is the biggest ongoing field development project in the Norwegian Sea. It is one of the main projects in Statoil’s portfolio. The plan for development and operations (PDO) was approved by the Norwegian Ministry of Petroleum and Energy in 2013. Production start-up is expected in 2017.

Exploration well 6706/12-3 is situated in PL602 in the Norwegian Sea. Earlier this year, Statoil increased its equity share in PL602 through transactions with Rocksource ASA and Atlantic Petroleum Norge AS.

Subject to government approval, the PL602 partnership will consist of Statoil Petroleum AS (operator, 42.5%), Petoro AS (20%), Centrica Resources (Norge) AS(20%), Wintershall Norge AS (10%) and Atlantic Petroleum Norge AS (7.5%).




Oil Price Drop Special Coverage

Oil prices rallies over US shale production dip with small gains News Agencies + NewBase

Crude prices rose today , Tuesday 14th April 2015 after the US Energy Information Administration said it expected US shale oil output to record its first monthly decline in over four years. Front-month Brent crude futures were trading up 34 cents a $58.27 a barrel by 0106 GMT, while US crude had risen 31 cents to $52.22.

The EIA expects US shale production to fall by 45,000 barrels to 4.98 million barrels per day in May from April. That would underscore how record crude output from the US shale boom may be backtracking after global markets saw prices effectively slashed by 60 per cent since June on oversupply and lacklustre demand. While political instability in the Middle East also helped push prices higher, analysts said that high global production and stocks were capping gains. "Geopolitical risk in oil markets remains elevated. From a fundamental perspective however, supply from the Middle East is expected to remain high, with Saudi Arabia and Iraqi production on the rise," JP Morgan said in a note. "Our base case is for crude stocks to decline through 2015, as US production is expected to turn lower in 2Q2015. If production, however, remains unchanged through the remainder of 2015, US crude stocks will likely increase to above 540 million barrels during the fall refinery maintenance period," it said.




US inventories in the week to April 3 surged nearly 11 million barrels to a fresh record high of 482.4 million, the US Department of Energy said. Meanwhile in Saudi Arabia, Oil Minister Ali Al-Naimi announced output hit a record 10.3 million barrels a day in March. The global oil market lost about 60 percent of its value to about $40 per barrel between June and late January, owing largely to an oversupply in world markets and the OPEC’s refusal to cut production. The drop in big oil companies’ profits in the past eight months isn’t just a function of lower crude prices - it also reflects strategic choices. A Reuters examination of corporate filings by some of the biggest players in the industry, including BP, Shell and France’s Total, shows the sensitivity of these companies’ earnings to changes in oil prices has risen in recent years. This means that for every dollar the oil price drops, their profits sink more than they might have done five years ago. Choices made by several oil majors that built more exposure to prices into their portfolio, mainly through the kinds of contracts they opted to sign, was aimed at enjoying prices that were historically high.

Japan’s nuclear industry pledges to refire reactors Oman Observer + AFP

Japan’s pro-nuclear lobby pledged on Monday that 2015 would be the year reactors are restarted, despite public wariness that has lingered since the Fukushima disaster. Industry officials and supporters said the country desperately needs atomic power to play its part in cutting greenhouse gas emissions and to ensure a stable electricity supply. “This year marks the exit from zero nuclear power,” Takashi Imai, Chairman of the Japan Atomic




Industrial Forum, told an audience of around 900 people, including industry officials and global policymakers. “It is self-evident that nuclear power plants that have passed safety tests should be restarted as soon as possible,” he said, citing the need for a stable power supply. Japan’s atomic watchdog last year gave the green light to restarts for four reactors — a move welcomed by pro-nuclear Prime Minister Shinzo Abe. The push from the nuclear industry comes as the public remains deeply concerned about safety, more than four years after a tsunami sparked meltdowns at Fukushima, spreading radiation over a large area and forcing tens of thousands of people from their homes.

It also comes as Japan prepares to decide its new energy policy — how much electricity will come from renewables, nuclear and fossil fuels — and readies to make a new international pledge on cutting greenhouse gas emissions before a global summit on climate change this year. Yukiya Amano, Director General of the International Atomic Energy Agency (IAEA), said the atom could not be forsaken. “Despite the Fukushima Dai-ichi accident, nuclear power has continued to play an important part in the global energy mix,” he said. “Nuclear power can make countries more competitive by delivering the steady supply of base-load electricity which is needed to power the modern economy. It also helps to reduce emissions of greenhouse gas,” Amano said. — AFP




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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 09 April 2015 K. Al Awadi







Economy & Finance

New base 582 special 14 april 2015