New base 793 special 23 february 2016

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,

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

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NewBase 23 February 2016 - Issue No. 793 Edited & Produced by: Khaled Al Awadi

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

UAE:Bee’ah takes a stand on recycling at Plastivision Arabia ‘16

(WAM) -- The third edition of the Plastivision Arabia International Plastics Exhibition and Conference gets under way from 22–25 February, at the Expo Centre Sharjah, with Bee’ah, the Sharjah Environment Company set to take a leading role as the event’s official recycling sponsor.

Held in association with the All India Plastics Manufacturers’ Association (AIPMA), the oldest and largest apex body in the plastics industry, Plastivision Arabia 2016 welcomes representatives and exhibitors from across the industry’s many sub-sectors, including polymer and machine manufacturers, processors, mould and die manufacturers, traders, exporters, consultants, environmental institutions and many more.

As the official recycling sponsor of Plastivision 2016, Bee’ah showcases a range of its significant eco-friendly products and services, such as its Tyre Recycling Facility (TRF) and Construction and Demolition Waste Recycling Facility (CDW) products.

Bee’ah’s recycled products include crumb rubber used in different rubber flooring applications such as jogging tracks, miniature golf courses as well as artificial turf infill in schools, parks and athletic facilities.

Bee’ah also manufactures rubber tiles of different shapes and thicknesses these are widely used as a safety flooring alternative for kids play areas, walkways, and in horse stables and exercise areas.

Moreover, recycled products from Bee’ah’s CDW Facility are reused as aggregate for roads, pavements, and landscaping. Plastivision 2016 is held at the Expo Centre Sharjah until the 25th of February, from 10am–6pm daily.




Qatar to build 1,000 MW of solar power capacity Reuters

Qatar plans to build around 1,000 megawatts of solar power generating capacity to diversify its energy mix away from hydrocarbons, the general manager of the state utility said. Qatar Electricity and Water Company said in late December it would hold 60 per cent of a new solar power joint venture with Qatar Petroleum . The two shareholders will provide $500 million of

start-up capital, Fahd al-Mohannadi told reporters on the sidelines of QEWC's annual shareholder meeting. International companies will be invited to back 40 per cent of each project through a competitive tender process, Mohannadi said. "We decided to do it based on the fact that producing power

from solar is cheaper than buying gas from the international market," Mohannadi said. Qatar is the world's largest exporter of liquefied natural gas. He did not say when it would reach 1,000 MW of generating capacity. Abdulsattar al-Rasheed, business development director at QEWC, said setting up the joint venture should be completed around the end of this year or early in 2017. There is little commercial generation of solar power in the Gulf, but oil-exporting countries around the region are starting to develop it, citing environmental reasons as well as a desire to conserve oil and gas reserves for export in the future. Two projects in the United Arab Emirates are expected to be tendered this year which would create 1,150 MW when fully operational. Saudi Arabia has plans for both small solar schemes and power plants in which a solar component is combined with a fossil fuel element. Mohannadi said solar would be a key part of Qatar's future energy mix, since both coal and wind power had been ruled out and Qatar's land mass was too small to consider nuclear power. DEMAND Peak demand for both electricity and water was expected to grow at 6 to 8 per cent this year, from last year's daily highs of around 7,000 MW and 330 million gallons of water, Mohannadi said. However, the country has plenty of spare capacity and more coming online in the next two years, which will take generating capacity to 11,000 MW of electricity and 400 million gallons of water by the start of 2018. The first phase of the Ras Abu Fontas A3 water plant expansion, built by a consortium led by Mitsubishi Corp , is due to be completed in September and will be fully operational in January




2017 when it produces 36 million gallons daily, according to a document distributed to shareholders. The Umm Al Houl power plant, also built by Mitsubishi and with total production capacity of 2,520 MW of electricity and 136.5 million gallons, will come on line in phases between April 2017 and July 2018, the document said. Ras Abu Fontas will cost QR1.75 billion ($480.6 million) and will be funded by loans from local banks, the document said. The cost of Umm Al Houl has already been disclosed at QR10 billion.




Qatargas, Maersk Group, Shell to Promote LNG as Marine Fuel in Middle East

Qatargas, the Maersk Group and Shell signed a Memorandum of Understanding (MoU) to explore the development of LNG as a marine fuel in the Middle East region.

Through the joint relationship the partners plan to explore the development of new markets for LNG to be used as propulsion fuel for merchant vessels. The memorandum envisages LNG supplies for this initiative to be made available from Qatargas 4, a joint venture between Qatar Petroleum and Shell Gas B.V., with Maersk Line potentially using the fuel for its merchant vessels, Qatargas said Monday.

The MoU was signed at a ceremony attended by Saad Sherida Al-Kaabi, Chairman of Qatargas Board of Directors, Qatargas Chief Executive Officer, Khalid Bin Khalifa Al-Thani, the Maersk Group Chief Executive Officer, Nils S. Andersen and Shell International Trading Middle East Limited General Manager, Danny Leek.

“We are very proud to continue to pioneer new

and novel opportunities to utilize Qatar’s LNG. We are also proud to partner with industry leaders such as Maersk and Shell to create potential new market opportunities for Qatar’s LNG and, at the same time, provide ship operators around the globe with a cleaner fuel alternative to the heavy fuel oils currently in use,” Saad Sherida Al-Kaabi, Chairman of Qatargas Board of Directors, said. Nils S. Andersen, Maersk Group Chief Executive Officer said the possible use of LNG as fuel for ships presents an opportunity to reduce both SOx emissions and in reducing the transport sectors CO2 foot print.

Michiel Kool, Managing Director and Chairman of Qatar Shell Companies added: “LNG fuel is a new alternative for ship and vessel operators responding to stricter emission control standards. Shell has been a pioneer in this area with our investments in LNG for transport infrastructure in Europe and the US, and we look forward to now deploying our expertise to create a regional hub in the Middle East in collaboration with Qatargas, the largest LNG producer in the world and Maersk, the world’s largest shipping container company”.




Algeria: Petroceltic commences development drilling on the Ain Tsila Source: Petroceltic International

AIM listed Petroceltic International has announced the start of development drilling on the Ain Tsila gas and condensate field in Algeria. The newly built SINOPEC Rig 50117 arrived on the Isarene permit during November 2015, was assembled successfully on site, and has now passed acceptance testing. At 18:00 on 21 February 2016 development well AT-10, the first well of the Ain Tsila development drilling campaign, was spudded.

AT-10 is located in the north of the field approx. 3.4 km from the field discovery well AT-1, and 2.0 km from the appraisal well AT-8; each of these wells delivered gas flow rates in excess of 30 MMSCFD on test. This vertical well is targeting the Ordovician reservoir formation to a planned total depth of 1,989m MD. AT-10 is the first of up to 24 new development wells on Ain Tsila expected to be required to establish and maintain the currently approved annual average wet gas plateau rate of 355 MMscfpd.

In addition to the commencement of development drilling, the tender of the major field Engineering Procurement and Construction ('EPC') contract covering main field facilities and pipelines is progressing.

Petroceltic holds a 38.25% interest, Sonatrach a 43.375% interest, and Enel an 18.375% interest in the Isarene PSC. Petroceltic continues to benefit from a carry of its development costs in respect of Ain Tsila following the completion of the sale of an 18.375% interest to Sonatrach in July 2014.

Background

Petroceltic was awarded operatorship of the Isarene PSC in April 2005 with a 75% equity interest, this was subsequently reduced to 56.625% through the divestment of an 18.375% interest to Enel SpA in early 2012, and reduced further to 38.25% through divestment of a further 18.375% to Sonatrach in 2014.




After the initial Ain Tsila discovery in 2009, Petroceltic applied for a two year extension period, from the end of the exploration period in April 2010 through to 26 April 2012, to allow time for the appraisal of the gas accumulation. During this period, the Group drilled six appraisal wells on the Ain Tsila structure.

Approved development plan

Following the completion of the appraisal drilling campaign and technical and economic studies, a full field development plan was submitted to the Algerian authorities and approved in December 2012. The plan envisages the production of 2.1 Tcf of sales gas and 179 MMbbl of liquids (comprising 69 MMbbl of condensate and 110 MMbbl of liquid petroleum gas or “LPG”) from the field during the 30 year Production Sharing Contract (“PSC”) exploitation period. The initial plan will result in a recovery factor of 24% of the Gas Initially in Place (‘GIIP’) in the field and the Company anticipates that the recovery factor is likely to grow over time with additional well data and the potential installation of additional gas processing facilities.

The field plateau production rate is forecast to be 355 MMscfpd gross wet gas and the plateau should last for some 14 years. The development plan involves the drilling and completion of 124 vertical development wells, of which 30 (including 6 existing wells) are scheduled to be available prior to first production. Along with basic in-field support infrastructure, the facilities will comprise a gas processing plant with water separation, condensate and LPG recovery equipment, gas compression, export pumps and metering facilities. The gas will be evacuated via a 95 kilometre pipeline which will tie into the main Algerian gas transmission network near the Tin Fouye Tabankort field. Dedicated condensate and LPG export lines will also be constructed to tie into liquids transmission infrastructure.

The gross project cost prior to first production is expected to be in the region of $1.6 billion with the majority of the expenditure incurred from 2016 through 2018. The capital estimate and phasing will be confirmed in more detail after the FEED studies have been completed and EPC contract awarded in late 2015.

Gas commercialisation

Following the execution of a legally binding Heads of Terms for the Gas Sales Agreement with Sonatrach in 2012, the comprehensive Gas Sales Agreement detailing operation procedures and processes required for nominations and payments was signed in September 2014 and approved by the Algerian Energy Ministry in November 2014.




Liquids

Condensate and stabilised LPG form a significant part of the reserves and revenues from the Ain Tsila field. Based on data from similar developments, the Company anticipates that both condensate and LPG will be sold in the local market at a price related to Brent.

Second farm-out

A process to divest an additional 18.375% of Petroceltic’s equity in the Isarene PSC was initiated in 2012 as part of the Company’s strategy to manage its overall financial and operational commitment to the Ain Tsila development. In early 2013, Petroceltic agreed a farm-out proposal from an international oil company and initialled a Sale and Purchase Agreement. However, in July 2013, Sonatrach exercised their right to pre-empt the transaction and acquire the interest on similar terms.

The agreement to effect the transfer of the interest to Sonatrach was signed in February 2014 and ratified by the relevant Algerian government authorities in June. The consideration included a $20m initial cash payment, a cost carry of up to $140m and two potential further $10m payments contingent on the achievement of certain key project milestones. Petroceltic retained a 38.25% interest in the project through to first gas.

The farm-out has resulted in a reduction in Petroceltic’s booked proved plus probable reserves from 300.0 MMboe to 202.7 MMboe, which has been reflected in the Company’s year end 2014 reserves

Isarene concession timeline

2005 Award of Isarene Production Sharing Contract

2006 First exploration drilling of two wells

2008 3D seismic acquisition

2009 Five wells drilled, resulting in the Ain Tsila discovery, the year’s 9th largest worldwide

2010 Two year delineation licence extension awarded

2011 Successful six well drilling campaign

2012

Farm-out of 18.375% interest to Enel Declaration of Ain Tsila field commerciality Development Plan and Gas Sales Heads of Terms approval Award of 30 year exploitation licence Booking of 304 MMboe of proved plus probable reserves

2013 Formation of joint operating organisation to develop the field FEED tender issued to market

2014

FEED contract awarded and studies commence Farm-out of 18.375% interest to Sonatrach Drilling contracts tendered

2015

Mobilisation of Joint Operating Organisation to Hassi Messaoud Rig contract awarded Major project EPC contract to be tendered and awarded Commencement of development drilling

2016-2018

Project execution phase including, drilling 24 wells and constructing gas processing plant and related infrastructure




Groupement Isarene

When the Isarene PSC was awarded in 2005, Petroceltic was qualified as an operator in Algeria. During the initial exploration and appraisal phase of activity, almost 10,000 km of 2D and 900 sq km of 3D seismic were shot, processed and interpreted, supporting the drilling and testing of 13 wells and the preparation of a field development plan for the Ain Tsila gas field. Enel joined Petroceltic as an investor in the field in 2012.

Following approval of that development plan by the Algerian authorities at the end of 2012, Sonatrach became a paying participant in the exploitation phase in respect of its 25% interest. Upon commencement of this phase, the responsibility for the execution of petroleum operations on the Isarene permit passed to a newly constituted Joint Operating Organisation called ‘Groupement Isarene’. This entity was set up in mid-2013 under the control of the PSC parties. It is financed by monthly cash calls to the Isarene PSC partners and is directed by a management council with representation of all the PSC parties.

Prior to the constitution of the Groupement Isarene, Petroceltic and Sonatrach negotiated the organisational structure and the allocation of positions between the parties, and, through the course of 2013, Petroceltic redeployed or recruited more than 50 experienced professionals on behalf of itself and Enel to take up these positions, primarily in management, supervisory, finance and technical roles. These secondees are located alongside their Sonatrach counterparts in the Groupement offices in Hassi Messaoud (the oil and gas operating and logistical centre of Algeria).

Through 2014, the Groupement project team concentrated on the preparation of the contract tender packages for the Ain Tsila production facilities and infrastructure FEED and development drilling. The FEED contract was awarded to Chicago Bridge & Iron BV in the Netherlands, and the drilling rig contract was awarded in 2015, to Sinopec International Petroleum Services Corporation.

In 2015, the development operations will ramp up with the preparation of the tenders for the main production facilities construction packages, the award of those construction packages, and the commencement of drilling. In the Ain Tsila field, a forward operations base and basic infrastructure will be constructed, allowing for the mobilisation of drilling rigs and construction crews in the second half of 2015. This will ensure that the required number of wells are available to be hooked up for production at first gas in Q4 2018.

In line with other operators in Algeria, the Company has prepared and issued a Development Security Philosophy to ensure appropriate security controls for all in-country activities. The FEED study will address a number of these critical controls – physical, procedural, organisational – and ensure that best practice is designed and engineered into all aspects of construction and subsequent operation of the project facilities.




Pakistan: Jura Announces gas discovery in Badin IV South Jura + EINPresswire + NewBase

Jura Energy Corporation ("Jura") today announced a potential gas discovery at the Aminah-1 exploration well in the Badin IV South block.

Jura holds a 27.5% working interest in the Badin IV South block, which is operated by Petroleum Exploration (Private) Limited ("PEL"). At the present time, PEL has not provided drilling depth, testing results or other status information with regard to the drilling of Aminah-1 directly to Jura, and Jura has not independently verified the discovery.

From time to time, Jura has been involved in various legal or administrative proceedings involving PEL. At present, Jura and PEL are in dispute with regard to, among other things, a past cash call for the Badin IV South block pursuant to which PEL has commenced proceedings with the Government of Pakistan to attempt the forfeiture of Jura's working interest in the Badin IV South block.

Jura and the other non-operated working interest holder challenged the validity of the cash call, which was in any event paid. Jura disputes the claim by PEL that Jura is in default under the Badin IV South joint operating agreement and that Jura's working interest in the block is validly subject to forfeiture.

Jura will vigorously defend its interest in the Badin IV South block and further information with regard to the potential discovery as well as the proceedings with PEL will follow in due course.




Indonesia: Oil and gas investors return 15 exploration blocks to regulator Source: Reuters

Oil and gas investors relinquished 15 exploration blocks to the Indonesian government in 2015, nearly double those they returned the previous year, according to the country's energy regulator, amid low oil prices and slowing global demand growth.

Indonesia's energy sector has seen a string of production curbs and asset cuts in recent months, with companies reeling from crude prices that have improved little since hitting a 12-year low in Jan.

Energy production is an important source of Indonesia's state revenues, and many of the big fields that have propped up its budget in recent decades are declining, with low oil prices limiting the prospect of increased recovery or finding new sources. Oil and gas companies lost $820 million on exploration and other costs for the 15 blocks handed back to the government last year, Amien Sunaryadi, chairman of the upstream oil and gas regulator (SKKMigas), told a parliament hearing on Monday.

Companies usually hand back exploration assets when either they have made no discoveries or the prospect of extracting reserves from them is seen as uneconomical. Under Indonesian law companies can only begin to recover costs once oil and gas blocks start producing.

No company names were given in the presentation to parliament on Monday. The amount lost in 2015 is almost three times as much as the $283 million spent on eight blocks relinquished by contractors in 2014, Sunaryadi said, and nearly double the $456 million spent on the five blocks that were relinquished in 2013.

Indonesia's top crude producer, Chevron Corp, announced last month it would not extend its contract to operate the East Kalimantan oil and gas block, after revealing plans in December to sell its stake in the South Natuna Sea Block B.

Output from Southeast Asia's biggest crude producer has been declining steadily from just above 1.6 million barrels per day (bpd) in the mid-1990s, and could slip to 753,400 bpd this year from 779,000 bpd in 2015 if oil prices hit $20 per barrel, the regulator said earlier this month.

Oil prices jumped higher on Monday following steep losses in the previous session, supported by a fall in the U.S. rig count, but analysts said oversupply was still capping the market.




UK Output Could Halve By 2025 If Money Dries Up Reuters

British oil and gas production could halve by 2025 if oil companies do not spend enough to squeeze every last drop out the North Sea, industry group Oil and Gas UK warned on Tuesday. Oil and gas companies, including former North Sea heavyweights BP, Shell and Statoil, have slashed their budgets by billions of dollars as they grapple with a 70 percent fall in oil prices.

Britain, one of the oldest oil and gas basins, has been hit especially hard as low revenue prospects are coupled with some of the world's highest exploration and production costs.

New investments in the UK Continental Shelf, Britain's offshore oil and gas production area, are expected to sink to less than 1 billion pounds ($1.4 billion) this year, compared with an annual average of 8 billion pounds over the past years.

"The outlook where we're seeing little fresh investment coming is the scary bit in all of it," Mike Tholen, Oil and Gas UK's economic director and author of its annual report, told Reuters. "We're a very simple industry: if you don't keep investing, you're not likely to see a good future in the North Sea."

The British government last year cut oil and gas taxes to prevent companies from leaving the North Sea and established a dedicated oil regulator to help them maximise output.

Oil and Gas UK said more tax relief is needed in next month's annual budget to ensure companies continue investing, echoing demands from the Scottish government, whose economy is heavily oil and gas dependent.

The oil price fall has accelerated the permanent shutdown of some fields, with 21 ceasing production in 2015, and Oil and Gas UK said as many as 80 could follow by the end of 2020. Almost half of Britain's oil and gas fields will be loss-making this year if oil prices remain at current levels around $30 a barrel, the lobby group said.

"Were a number of these fields to cease production, their interconnectivity would mean many more could become sub-commercial, known as the 'domino effect'," the report said. As oil prices are expected to remain weak, the group expects more job losses in the sector this year after a fall of around in employment in 2015.




Chancellor urged to use budget to support ailing North Sea oil industry

Key oil industry figures have called on the chancellor to use next month’s budget to prop up the North Sea oil industry after a collapse in investment.

The trade body Oil & Gas UK called for permanent tax breaks, warning that low Brent crude prices were choking off the investment needed to extract the oil left under the North Sea.

It expects cash-strapped members to spend just £1bn on new projects this year, compared with an annual average of £8bn over the past five years.

It came as the International Energy Agency warned that investment cuts worldwide meant that when prices start to rise – as it expects in 2017 – they are likely to jump sharply.

Fatih Birol, executive director of the IEA, said: “It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but they should heed the writing on the wall: the historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in the not too distant future.”

The agency forecast that global oil supply would grow by 4.1m barrels a day between 2015 and 2021; in the previous six years it grew by 11m barrels a day.

Oil & Gas UK said the North Sea firms had tried ensure the industry stayed afloat by slashing costs. It said oil explorers on the UK continental shelf cut the cost of production by 40% from an average $29.30 a barrel in 2014 to $20.95 last year.

But the oil price has tumbled by about 70% – or more than $100 a barrel – since the summer of 2014, wiping out the effect of the cost-cutting drive.

Oil & Gas UK said that while firms could make further cuts, they would struggle to afford investment with oil hovering at about $30 a barrel. It called for urgent changes to the taxes paid by North Sea companies, warning of heightened fears over the long-term future of the industry.




Oil companies were handed tax relief last year when George Osborne reduced their rate to 50%, or up to 67.5% on some fields where petroleum revenue tax also applies. But Oil & Gas UK said the chancellor must go further or risk seeing the North Sea’s decline accelerate, adding to job losses in the industry. “A significant, permanent reduction in those rates is now urgently needed,” said Oil & Gas UK’s chief executive, Deirdre Michie.

The trade body pointed to the potential impact of a shrinking oil industry on the wider economy. It said total capital expenditure fell from £14.8bn to £11.6bn last year and predicted it would drop further, to £9bn this year.

A study by Rystad Energy found that the supply chain serving the North Sea shrank by about 25% last year and was expected to contract further this year. The increasing difficulty of making money in the North Sea is also speeding up decommissioning, where companies shut down oilfields that are no longer economically viable.

This has seen reserves held by companies for future development fall from 10bn to 8.8bn barrels of oil, compared with Oil & Gas UK’s estimate of 20bn barrels remaining overall. The trade body believes that decommissioning will cost up to £55bn by 2050, while Revenue & Customs estimates that the taxpayer will pick up £16bn of the bill through tax relief on decommissioning.

Oil & Gas UK warned that “the pace of decommissioning is accelerating”, indicating that the cost of dismantling old oil platforms and cleaning up after them could rise still further.

The accelerating decline of the North Sea is forecast to punch a hole in the UK’s tax take, even as Osborne battles to erase the deficit. The Office for Budget Responsibility predicts receipts of £130m from the North Sea in 2015-16, compared with £11bn four years previously.




US: Pipelines, tankers, and barges convey transportation fuels from Gulf Coast to East Coast

Source: U.S. Energy Information Administration, PADDs 1 and 3 Transportation Fuels Markets

In the United States, the East Coast and Gulf Coast are highly dependent on each other to balance supply and consumption of transportation fuels (mainly gasoline, diesel, and jet fuel). East Coast transportation fuels consumption is met through a number of supply sources, but none is more important than supply from the Gulf Coast. Conversely, surplus supply in the Gulf Coast is distributed to a number of domestic and foreign markets, but none is larger than the East Coast.

EIA has commissioned studies of transportation fuels supply, consumption, and distribution in certain regions of the country, as defined by Petroleum Administration for Defense Districts (PADDs). The most recent study involves the East Coast and Gulf Coast regions and nine sub-PADD regions: four in the East Coast and five in the Gulf Coast.




Two pipelines, the Colonial Pipeline and the Plantation Pipeline, typically operate at or near full capacity and in 2014 moved approximately 2.3 million barrels per day (b/d) of transportation fuels from the Gulf Coast to the East Coast. The Colonial system consists of 5,500 pipeline-miles and has connections to 29 refineries and 267 customer terminals. The Plantation system consists of 3,100 pipeline-miles and 36 pumping stations and has connections to 90 terminals at 34 delivery locations.

An additional 0.5 million b/d of transportation fuel is shipped from the Gulf Coast to the East Coast by coastwise-compliant tankers and barges, primarily to ports in Florida. Together, net pipeline and waterborne shipments from the Gulf Coast to delivery points in the East Coast are equal to 58% of East Coast consumption and 37% of Gulf Coast supply.

Waterborne movements—both coastwise and internal river movements—connect supply and consumption centers between and within the Gulf Coast and East Coast regions. The Gulf Coast region, particularly the areas of Texas and Louisiana near the coast, is characterized by large outbound shipments of products primarily delivered to markets in the East Coast (especially Florida) and to export destinations, but also to coastal and riverine markets in other areas of the Gulf Coast as well as the Midwest.

More information on East Coast and Gulf Coast transportation fuels markets is available in PADDs 1 and 3 Transportation Fuels Markets. An earlier study evaluated transportation fuel markets in the Pacific Coast region (PADD 5).




NewBase 23 February 2016 Khaled Al Awadi

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

Oil dips as rising Iranian output to counter falling U.S. shale production Reuetrs = NewBase

Oil prices dipped slightly in early trading on Tuesday after posting strong gains the previous session on the back of an expected drop in U.S. production, but which analysts expect to be countered by rising output from Iran.

U.S. front-month West Texas Intermediate (WTI) crude futures, were trading at $33.10 per barrel at 0118 GMT, down 29 cents from their last settlement. International benchmark Brent was down 21 cents at $34.48 a barrel.

Tuesday's dips came after strong gains in the previous session on the back of an expected fall in U.S. oil production this year. Production of shale oil is expected to drop by 600,000 barrels per day (bpd) this year and a further 200,000 bpd in 2017, according to the International Energy Agency (IEA).

"Crude supply growth from Iran will more than compensate for any decline in U.S. output," ANZ said. The IEA said that in the longer term, U.S. production would also recover thanks to improving cost efficiency, lifting output to a record 14.2 million bpd by 2021, compared with a peak of over 9.5 million bpd in 2015.

The expected resurgence of U.S. shale oil production will cap a recovery in the coming years in the price of oil, which is expected to reach $80 per barrel by 2020, IEA Director Fatih Birol said at a news conference in Houston, Texas.

Oil price special

coverage




IEA warns against complacency over ‘ample’ oil stocks The National - LeAnne Graves + NewBase

The oil market is resembling the 1980s as the International Energy Agency (IEA) forecasts lower investments and no short-term price recovery.

The IEA released its five-year outlook that forecasts 4.1 million barrels per day added to the global oil supply from 2015 to 2021, which is more than a 60 per cent decrease from the previous outlook from 2009 to 2015.

This has signaled to a fall in capital expenditures with a 17 per cent drop this year on top of last year’s 24 per cent cut. This is the first time in three decades that the industry investments have shrunk for two consecutive years.

“It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but they should heed the writing on the wall: the historic investment cuts we are seeing raise the odds of unpleasant oil security surprises in the not-too-distant-future,” said Fatih Birol, the IEA’s executive director, launching the report at IHS CeraWeek, the energy conference held annually in Houston.

While supply may decrease as a result of declining investments, the US shale revolution is not expected to dry up any time soon. The IEA suggests a short-term reduction, with a revival only likely to come from greater operational efficiencies.

“But at the risk of tempting fate, we must say that today’s oil market conditions do not suggest that prices can recover sharply in the immediate future – unless, of course, there is a major geopolitical event,” said the IEA.

Sebastien Henin, the senior vice president of Abu Dhabi-based advisory firm The National Investor, said the report stated the obvious. “It’s nothing new. Demand is still robust. The oversupply is here for the entire year and the market should be balanced next year,” he said.

Global oil glut to persist, limit price rebound




The global oil glut will persist into 2017, limiting any chance of a price rebound in the short term as the surplus takes even longer to clear than previously estimated, according to the International Energy Agency.

While US shale oil production will retreat this year and next as the price slump hits drilling, its subsequent recovery will ensure America remains the biggest source of new supply to 2021. The Organization of Petroleum Exporting Countries will expand its market share slightly this decade, with Iran, newly released from international sanctions, displacing Iraq as the organisation’s biggest contributor to supply growth.

“Only in 2017 will we finally see oil supply and demand aligned but the enormous stocks being accumulated will act as a dampener on the pace of recovery in oil prices,” the Paris-based adviser to 29 countries said in its medium-term report yesterday. “It is hard to see oil prices recovering significantly in the short term from the low levels prevailing.”

The IEA’s new outlook is the latest sign that oil forecasters are bracing for a “lower-for-longer” price environment. The agency acknowledged that the industry’s expectations - and its own predictions - that oil markets would recover in 2015 proved “very wide of the mark.” The report also signals that while Opec will succeed in its policy of defending market share, the group will have to endure an extended period of reduced revenues.

Oil futures have sunk by 42% in the past year as the global surplus was prolonged by resilient US crude production, increased supply from key Opec members and slowing economic growth in China.

After declining this year, supply from outside Opec will remain stable in 2017 and recover in 2018, growing by 2mn barrels in the six years to 2021 to reach 59.7mn bpd. Prices won’t need to rebound to $100 a barrel to finance that new output, the agency said.

While US production of shale oil, also known as light-tight oil (LTO), is projected to retreat by 600,000 bpd this year and a further 200,000 a day in 2017, it will still expand during the period as a whole as growth resumes. Total US liquids output will increase by 1.3mn bpd by from 2015 to 2021 as drillers lower costs and improve efficiency.

“Anybody who believes that we have seen the last of rising LTO production in the US should think again,” the IEA said.

The agency increased estimates for global oil demand each year to 2020, mostly as a result of revisions to historical or “baseline” data. The estimate for annual growth in world fuel consumption remains at a “very solid” average of 1.2% through to 2021, when it will reach 101.6mn barrels a day.

As a result of the increase in demand and weaker growth in supply, Opec’s share of the total market for crude will reach 33.8% in 2020, up from last year’s projection of 32.4%. The amount of crude required from exporters’ group will expand to 34.8mn bpd by 2021, compared with production of 32.1mn last year, the IEA said.

Much of the boost in Opec supply will come from existing facilities, with the organization set to add only 800,000 bpd of new capacity in the period to 2021 as members outside the low-cost Middle East struggle to grow. Capacity will stagnate or shrink slightly in Algeria, Angola, Ecuador, Indonesia, Nigeria, Qatar and Venezuela.




Over the longer term, sharp cutbacks in investment leave global supplies exposed to “unpleasant oil-security surprises in the not-too-distance future,” according to the IEA.

Spending on new output will fall by 17% in 2016 after a 24% collapse last year, mostly in the US As a result of the cuts, the agency lowered its estimates for non-Opec supply for each year except 2016, with Russian supply set to suffer the steepest decline in the period.

“It is very tempting, but also very dangerous, to declare that we are in a new era of lower oil prices,” the agency said. “The risk of a sharp oil price rise towards the later part of our forecast arising from insufficient investment is as potentially destabilising as the sharp oil price fall has proved to be.”

NewBase Special Coverage

News Agencies News Release 23 February 2016




Apart from oil, Ecuador also exports bananas, shrimp, coffee, cocoa, cut flowers and fish. The country is a haven for many exotic

animals and birds like the blue footed booby, and the orange iguana, both of which can be found in the Galapagos Islands.

Ecuador’s President is HE Economista Rafael Correa Delgado. The country joined OPEC in 1973. Nineteen years later, in 1992, it

voluntarily suspended its membership. It resumed membership of the Organization in 2007.

Did you know?

• Ecuador’s capital city Quito was declared a World Heritage Site by UNESCO in the 1970s for having the best preserved

and least altered historic centre in Latin America.

• Located in the Santa Elena Peninsula, Ancon 1 is Ecuador’s first productive oil well. It began producing oil in 1921.

Population (million inhabitants) 16.027

Land area (1,000 sq km) 284

Population density (inhabitants per sq km) 65

GDP per capita ($) 6,308

GDP at market prices (million $) 101,094

Value of exports (million $) 26,604

Value of petroleum exports (million $) 11,401

Current account balance (million $) 718

Proven crude oil reserves (million barrels) 8,273

Proven natural gas reserves (billion cu. m.) 11.00

Crude oil production (1,000 b/d) 557

Marketed production of natural gas (million cu. m.) 578

Refinery capacity (1,000 b/cd) 191

Output of refined petroleum products (1,000 b/d) 201.0

Oil demand (1,000 b/d) 281

Crude oil exports (1,000 b/d) 422

Exports of petroleum products (1,000 b/d) 8.0




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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 23 February 2016 K. Al Awadi







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