new base 819 special 30 march 2016

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NewBase 30 March 2016 - Issue No. 819 Edited & Produced by: Khaled Al Awadi

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UAE: ADNOC 'Open' To More Partners At Onshore Oil Fields Bloomberg - Anthony DiPaola

Abu Dhabi National Oil Co. is willing to accept additional partners at its main onshore fields, a senior company official said, almost a year after awarding less than half the production rights it offered for the deposits in a bidding round.

The Arabian Gulf emirate, which holds about 6 percent of proven global oil reserves, is investing to boost output capacity to 3.5 million barrels a day of oil by 2017 from about 3 million currently. Total SA of France won a 10 percent stake in Abu Dhabi’s onshore joint venture, but other former partners in the project including Exxon Mobil Corp., BP Plc and Royal

Dutch Shell Plc either declined to bid or wouldn’t meet Adnoc’s terms.

“The door is open, if they can meet the technical and commercial requirements,” Abdul Munim Al Kindy, Adnoc’s director of exploration and production, said Tuesday on the sidelines of an event in Abu Dhabi. Al Kindy earlier this month left his role running the joint venture that operates the onshore concession to take over as head of exploration at Adnoc.

Al Kindy’s appointment was one of the first major personnel changes by Sultan Al Jaber, who became Adnoc’s new director general last month. Under Al Jaber, the company will focus on controlling costs and boosting production of natural gas as the sheikhdom seeks more of the fuel to run power plants and enhance recovery at oil fields, Al Kindy said.

Adnoc awarded a combined share of 18 percent of the onshore oil concession to foreign partners last year. That leaves 22 percent of the venture to be awarded to foreign firms if Abu Dhabi decides to maintain its 60 percent interest. Aside from Total, Adnoc’s other partners are Inpex Corp. of Japan, with a 5 percent stake, and South Korea’s GS Energy Corp., with 3 percent.




Kuwait says it agrees with Saudi to restart Khafji oilfield

The Khafji field was shut in October 2014 for environmental reasons, having been producing

between 280,000 and 300,000 barrels per day (bpd) Reuters + Gulf News + NewBase

Kuwait has agreed with Saudi Arabia to resume oil production at the jointly operated Khafji field, the Opec member state’s acting oil minister said on Tuesday, weeks before oil producers are set to agree a global output freeze.

Output at the joint Khafji field will be small and introduced gradually, Anas al-Saleh told reporters in the Kuwaiti parliament, without giving the date of the restart or planned production figures.

The Khafji field was shut in October 2014 for environmental reasons, having been producing between 280,000 and 300,000 barrels per day (bpd). It is operated by Al-Khafji Joint Operations Co, a joint venture between AGOC, a subsidiary of state oil firm Saudi Aramco, and Kuwait Gulf Oil Co.

Saleh said the agreement to restart had been made

with Saudi Aramco.

“Some maintenance contracts have been amended to produce in volumes that are in line with environmental requirements but (production) will go back to normal when all these requirements are met,” Saleh said.

The announcement of the restart comes with oil prices about 50 per cent higher than the multi-year lows hit in January, due to worries about an oversupply of crude. Opec and non-OPEC producers are set to meet in April in the Qatari capital Doha to agree on freezing production at January levels.

Wafra, another joint oilfield, has also been shut since May last year due to operating difficulties. US oil major Chevron operates the field on behalf of the Saudi government. The impact of the fields’ closures was more felt by Kuwait, which has less spare capacity than top Opec producer Saudi Arabia.

Arabian Gulf




UAE: Production at Abu Dhabi’s Shah gasfield to be ramped up Gulf News - Fareed Rahman, Senior Business Reporter

Gas production from Abu Dhabi’s Shah field is set to be increased by 50 per cent by 2021, according to the chief executive officer of Al Hosn Gas company, which is developing the project.

“We are planning to increase production to 1.5 billion cubic feet per day within five years from the present production capacity of one billion cubic feet per day,” Saif Ahmad Al Ghafli, chief executive officer of Al Hosn Gas said while spea king to reporters on the sidelines of an event to launch The Oil and Gas year report on Tuesday.

Al Hosn Gas is a joint venture between Abu Dhabi National Oil Company (Adnoc) and the US based Occidental Petroleum. The project began operations last year and reached its full capacity of one billion cubic feet per day in the second quarter. The main purpose of the project is to produce usable gas from Shah’s high-sulphur field. “We are really proud of this project. It has been done within a good time frame despite many challenges,” Al Ghafli said. The gasfield located about 210 kilometres south-west of Abu Dhabi will contribute significantly to the energy needs of Abu Dhabi and the UAE for over 30 years, he added.

The UAE has been focusing on developing gas projects to meet the rising demand for electricity generation. A gas project being developed by German company Wintershall is in progress near Shuweihat in the western region of Abu Dhabi. Bab sour gas project faced challenges after Royal Dutch Shell pulled out citing rising costs and technical difficulties.

According to the US based Energy Information Administration, the UAE holds the seventh-largest proven reserves of natural gas in the world, at slightly more than 215 trillion cubic feet (Tcf) but it has a high sulphur content that makes it highly corrosive and difficult to process. The UAE mainly imports gas to generate electricity from Qatar through the Dolphin energy pipeline.




Oman:Tender for large-scale renewable solar power project in this year Oman Observer

A tender for the procurement of Oman’s keenly awaited large-scale solar energy project is expected to be floated this year, according to the head of the nation’s power sector regulatory authority

Qais bin Saud al Zakwani, Executive President of the Authority for Electricity Regulation Oman (AER), said the proposed venture — envisioning one or more solar-based electricity generation plants with an aggregate capacity of up to 200 MW — will be procured as an Independent Power Project (IPP) similar to conventional gas-based power projects.

Two locations in Dakhiliyah Governorate — Adam and Manah — have been identified as prospective sites for the establishment of a grid-connected large-scale renewable energy scheme based on a combination of concentrated solar power and photovoltaic technologies.

“This year, we will launch a tender for up to 200 megawatts of solar energy capacity at these sites,” Al Zakwani said. “We hope to be using the same type of tendering mechanism for conventional power plants to these two large-scale projects in Adam and Manah.”

To help amass “bankable data” in support of this ground-breaking renewable energy initiative, solar radiation data is being collected from the two sites — a practice that began in 2010, he said. Oman Power and Water Procurement Company (OPWPC), a wholly owned subsidiary of Nama Group charged with overseeing the procurement of all new electricity generation and water desalination capacity, is overseeing the data collection process.

According to Al Zakwani, large-scale renewable energy development in the Sultanate is expected to make headway once the government rules on two key policy issues: One is the long-term National Energy Strategy 2040, which will allocate a certain quota for renewable energy in the wider energy mix; the other concerns the economic pricing of natural gas (the dominant source of fuel in conventional power plants), which is key to assessing the economic feasibility of large-scale renewable energy projects.




Ghana: Eni awarded new exploration licence offshore Ghana Source: Eni

Eni has been awarded a new exploration licence, the Cape Three Points Block 4, located in the prolific Tano basin, offshore Ghana. This acquisition will further strengthen the company’s position in the Ghanaian offshore.

The Cape Three Points Block 4 licence was awarded, following the ratification by the Parliament of the Republic of Ghana, to a joint venture which involves Eni Ghana (with 42.4691% stake) as operator, Vitol Upstream Tano (with 33.9753% stake), Ghana National Petroleum Corporation (GNPC with 10% stake),Woodfields Upstream Ghana (9.5556% stake) and GNPC Exploration and Production Company (Explorco, 4% stake). The new block covers an area of 1,127 sq kms in water depths ranging from 100 to 1,200 meters and partially surrounds the OCTP block also operated by Eni. In the event of a successful exploration outcome, the block will benefit from the OCTP project infrastructures, currently under development.

Eni operates the OCTP project, which involves the integration and synergic development of the various oil and gas discoveries (Sankofa Main, Sankofa East and Gye-Nyame). The project envisages the development of subsea wells tied-back to a FPSO which will be connected to shore via a gas transport line. The OCTP oil production start-up is expected in 2017 while the gas production, which will supply the domestic market for power generation, is expected in 2018.

Eni has been present in Ghana since 2009 where it operates through the subsidiary Eni Ghana. In the Country, the company has also undertaken important social programmes including the Health Project in the Western Region for the benefit of a population of over 300,000 people.




Norway: Crude at $40 Isn't the Only Problem in its Oil Industry Bloomberg - Mikael Holter

The collapse of crude prices isn’t the only problem facing energy companies in Norway: Explorers in western Europe’s biggest oil-producing nation also have had their leanest drilling spell in almost a decade.

Companies searching off Norway found less than 5 million barrels of oil and gas for every exploration well drilled last year, the lowest ratio since 2006, according to Bloomberg calculations based onNorwegian Petroleum Directorate data. That compares with a 27 million-barrel average over the past 25 years.

The dismal results, due in part to the depletion of the North Sea, are bad news for a country whose oil production has shrunk by half since 2000. The slump in prices has already dried up income from crude extraction, which feeds the world’s biggest sovereign wealth fund and has made Norwegians some of the richest people on the planet. In January the government made its first withdrawal from the fund since it was set up in the 1990s as the market rout eroded growth.

The dwindling drilling success has left the country’s top explorers -- Statoil ASA and Lundin Petroleum AB -- impatient to tap an entirely new region of the nation’s Arctic, bordering Russian waters. Norway plans to award licenses in an area known as theBarents Sea Southeast before summer and drilling could begin as soon as 2017. Go North




“Those blocks are probably the best acreage being offered in Norway since the 1990s,” Lundin Chief Executive Officer Alex Schneiter said in an interview in Oslo. “If you want to grow significantly in resources, go north.”

With crude trading around $40 a barrel following the worst downturn in a generation, that might seem like odd advice. Explorers including Statoil and Royal Dutch Shell Plc have fled other parts of the Arctic such as Alaska and Greenland, where extreme conditions and environmental risks make operations costly.

Two factors help explain why Statoil, Shell and others are salivating over new blocks in the region.

The Barents Sea, an area off Norway’s northern tip that’s the main focus of the country’s 23rd licensing round, is less hostile than other Arctic waters thanks to the Gulf Stream, with shallower and mostly ice-free access. And the Barents Sea Southeast, the first new acreage to be opened to exploration in Norway since 1994, could hold “gigantic structures,” according to consultants Rystad Energy AS. New Province

“The 23rd round is very exciting,” said Statoil Chief Financial Officer Hans Jakob Hegge. “Access to acreage is important to maintain stable activity” as the volumes discovered will tend to decline in a mature area, he said.

Norway is counting on the little-explored Barents Sea to become its next big petroleum province. So far, companies have drilled only 125 exploration wells there compared with 1,146 in the North Sea, according to the petroleum directorate. That includes wildcat wells, which are drilled at sites not previously explored, and appraisal wells, used to define a known reservoir. The NPD estimates that the Barents holds almost half of the country’s undiscovered oil and gas resources.

Eni SpA started production this month at the Barents Sea’s first oil field, Goliat. Statoil, Lundin and OMV AG have made other discoveries that are yet to be developed. No wells have been drilled in




the Barents Sea Southeast because the area was disputed by Russia for decades until a bilateral border agreement was reached in 2010.

The latest licensing round includes Norway’s northernmost blocks, despite protests from environmental groups and opposition parties that they’re too close to the polar ice-cap, meaning a spill could have disastrous consequences for an already fragile ecosystem sustaining animals from polar bears to birds and fish.

Statoil, Shell and Lundin were among 26 companies that appliedfor licenses in December, sending a “strong signal” of interest in the current market downturn, according to Jarand Rystad, managing partner at Rystad Energy.

Oil companies in Norway will cut spending for a third consecutive year and drill almost half as many exploration wells in 2016 than in 2015, the NPD forecast in January. Given the waning activity and exploration efficiency, opening up as much acreage as possible is “the only right thing” to do for the government, said Karl Johnny Hersvik, CEO of explorer Det Norske Oljeselskap ASA.

The biggest discovery in Norway in recent years -- the giant Johan Sverdrup field, which could hold as many as 3 billion barrels of oil -- was made in the North Sea, not the Barents. Yet while it showed the North Sea still has potential, even Lundin, which made the initial find in 2010, believes future success is more likely farther north.

“It was a shock wave to the whole industry, but I would say that certainly that area is mature -- it’s going to be less exciting than if you go north,” Lundin’s Schneiter said. In the Barents Sea, “we’re just scratching the surface. So I think there’s the card to play -- and maybe the next Johan Sverdrup,” he said.




U.S. production of LPG / NGL expected to increase through 2017 Source: U.S. Energy Information Administration, Short-Term Energy Outlook, March 2016

U.S. production of hydrocarbon gas liquids (HGL)—a group of products including ethane, propane, butanes, and natural gasoline—is expected to increase from 3.86 million barrels per day in 2015 to 4.33 million b/d in 2017, according to EIA's Short-Term Energy Outlook (STEO).

HGLs are produced at both natural gas processing plants and petroleum refineries, but natural gas plants are expected to provide more than 95% of the forecast production growth.

Between 2008 and 2015, HGL production at natural gas processing plants (including fractionation facilities) increased as a by-product of the growing supply of natural gas from shale gas and tight oil formations.

Projects that increased the capacity to produce, store, transport, export, and consume HGLs enabled the supply of HGLs to expand at a faster rate than natural gas production. STEO expects HGL production growth to continue to outpace natural gas production growth in 2016 and 2017, as more HGL infrastructure projects are completed.

Ethane production, which was constrained by lack of demand and low prices in recent years, is expected to increase at a faster rate than other HGLs in 2016 and 2017, as expanded petrochemical and export capacity provides new outlets for supply and allows more ethane to be recovered from raw natural gas. Forecast natural gas plant ethane production increases by 300,000 b/d between 2015 and 2017, accounting for two-thirds of total HGL production growth.




The United States, which was a net importer of all HGL products in 2007, became a net exporter of natural gasoline in 2008, of butane and propane in 2011, and of ethane in 2014. Annual average net propane exports (gross exports minus gross imports) increased from 10,000 b/d in 2011 to an estimated 500,000 b/d in 2015, as the capacity to export liquefied petroleum gas (LPG), including propane and butanes, increased by almost 1 million b/d.

STEO projects net propane exports to increase to 640,000 b/d in 2016 and to 740,000 b/d in 2017 as exports ramp up at two Gulf Coast terminal projects that began operating in the second half of 2015, and at another project scheduled to come online in the second half of 2016.

In March 2016, the first waterborne shipment of ethane left the United States from new ethane export facilities at Marcus Hook, Pennsylvania. A second ethane export facility is expected to open in the third quarter of 2016 at Morgan's Point, Texas. STEO projects net ethane exports to increase by 80,000 b/d in 2016 and by 90,000 b/d in 2017 as exports ramp up at these terminals.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, March 2016




NewBase 30 March 2016 Khaled Al Awadi

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

Oil prices rebound on less than expected build in stocks Reuters + NEwBase

Oil futures rebounded in Asian trade on Wednesday, buoyed by a forecast for a less than expected build in crude oil stockpiles last week. A weakening dollar also lent some support but concern that a two-month rally was fading in an oversupplied market put a ceiling on gains.

Brent futures climbed 40 cents to $39.54 a barrel as of 0104 GMT after settling down $1.13 in the previous session. U.S. crude rose 45 cents to $38.73 a barrel after ending the previous session down $1.11.

Oil prices fell about 3 percent in the previous session after Kuwait and Saudi Arabia said they would resume production at the jointly operated 300,000-barrel-per-day Khafji field even as oil output is supposed to be capped.

"There's a little bit of steadying in oil prices in the Asian time zone. The predominant attitude is one of wait-and-

see until the Energy Information Administration (inventory) figures come out," said Ric Spooner, chief market analyst at Sydney's CMC Markets. The EIA is due to release official crude inventory data later on Wednesday.

U.S. crude stocks rose last week by 2.6 million barrels to 534.4 million barrels data from industry group, the American Petroleum Institute, showed on Tuesday. That was less than analysts' expectations of a 3.3 million barrel build, but still a record high for a seventh straight week.

"The market is seeing how currencies go as well. It was slightly disconcerting for the market (on Tuesday) to see oil prices falling at the same time as the dollar was falling," Spooner said. The dollar index nudged lower on Wednesday after slipping to an eight-day low in the previous session. A weaker dollar makes greenback-denominate d commodities cheaper for holders of other currencies.

Rosneft, Russia's top oil producer, is set to lower oil output, Russian Natural Resources Minister Sergei Donskoi said on Tuesday, although he gave no time frame. The plan could be lending support to oil prices, Spooner said, although the impact would be muted because the market is already pricing in possible output curbs.

OPEC member Iran is expected to attend an oil producers meeting in Doha on April 17 to discuss a cap on global oil production, although it may not take part in the discussions, a source familiar with Iranian thinking said on Tuesday.

Oil price special

coverage




NewBase Special Coverage

News Agencies News Release 30 March 2016

Gartman: Forget a freeze, this is the biggest threat to oil CNBC - Leanne Miller | @LeanneBMiller

Oil watchers are eyeing a potential freeze by producers as the next catalyst for the commodity, but one oil bear says crude's biggest obstacle is already here.

"I think Uber is a threat to oil for the simple reason that millennials have embraced it dramatically," Dennis Gartman, editor of The Gartman Letter, told CNBC's "Fast Money" traders on Monday. "The millennials are saying 'I really don't need an automobile.'"

Since the founding of Uber in 2009, the ride-hailing company has launched in more than 400 cities and taken passengers on more than 1 billion rides, according to the company's website.

And it's the simplicity and convenience of the service itself that Gartman said has converted many would-be personal vehicle owners into Uber-dependent passengers. Oil has fallen more than 40 percent since Uber's inception.

This theory, he said, can be illustrated by taking a look at the history of U.S. total vehicle miles traveled, as reported by the Federal Reserve Bank of St. Louis.

"If you take a look at the average amount of driving that has taken place in the United States, it was a very well-defined trend line. We have broken that trend line dramatically," said Gartman. "That whole mystique of driving an automobile is lost and it's not coming back."

For Gartman, the ride-hailing company diminishes the demand for gasoline as well as automobiles — a bearish implication for ever-increasing oil production.

"I think on balance that is a terribly bearish circumstance," said Gartman.




The CNBC contributor stands by his theory that oil will continue to trade between $32 and $42 for the foreseeable future. In a "Fast Money" interview last month, the so-called Commodities King said he would not see $44 oil again in his lifetime.

"I think $42 is going to be very difficult to get through," said Gartman. "There are so many wells that have been capped that could be brought online very quickly."




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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

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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 30 March 2016 K. Al Awadi