New base 814 special 23 march 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 March 2016 - Issue No. 814 Edited & Produced by: Khaled Al Awadi

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

Saudi Aramco oilfield expansion nearing completion Reuters

The expansion of Saudi Arabia's Shaybah oilfield, which will boost production capacity from the southeastern field by 250,000 barrels per day (bpd), will be completed in few months, industry sources familiar with the matter said. State oil giant Saudi Aramco has said it was expanding the Shaybah and Khurais oilfields to rebalance its crude quality and help compensate for other mature fields, thus keeping Aramco's oil production capacity unchanged at 12 million bpd.

Shaybah's expansion is scheduled to be complete by the end of June, one of the sources said. A major natural gas liquids (NGL) project at Shaybah was completed with gas already flowing, the source added. The project was originally due to be finished in 2014 but faced delays mainly due to construction activities. The NGL plant, which has two trains, is expected to help meet increasing demand for petrochemical feedstock. "Both trains are under commercial

operation," said the source, who declined to be identified. The NGL project will process 2.4 billion cubic feet per day (cfd) of low-sulphur sweet gas from Shaybah and send on 264,000 bpd of NGLs for fractionation at an associated processing plant in Juaymah. Other industry sources also told Reuters the expansion of the Khurais oilfield would be finished by the end of 2017. The expansion project of Shaybah would take output capacity to 1 million bpd from 750,000 bpd now, while Khurais' potential will rise by 300,000 bpd to 1.5 million bpd. The original time frame to complete the expansion plans was 2016-2017. Saudi Aramco declined to comment on Shaybah, and said it did not comment on rumour or speculation in reply to a Reuters emailed question about the Khurais start-up date.




Qatargas eyes expanded LNG supply deals with UK, Dutch terminals Reuters + Gulf News + NewBase

Qatargas is looking to Britain and the Netherlands in an effort to weather a looming global glut of gas supplies by expanding import deals into Europe’s most liquid markets, industry sources said.

The world’s biggest exporter of liquefied natural gas (LNG) must lock in buyers for its unsold supply just as new Australian and US producers muscle into its prized Asian markets.

Slowing demand globally is only adding to producer woes, thrusting Europe’s gas markets and dozens of under-used import terminals into the spotlight.

Qatargas has held talks with Petronas UK Ltd to gain greater access to the Dragon import terminal in Wales, as well as with Uniper, formerly known as E.ON Global Commodities, for the Gate terminal in Rotterdam, two sources said.

Uniper declined to comment, while Qatargas and Petronas did not respond to requests for comment.

Stefaan Adriaens, commercial manager at Gate, said he could not comment on whether Qatargas was interested in increasing capacity at the terminal either via Uniper or directly. “They see competition in Asia, so if they are looking for capacity, then I presume it’s to have an alternative to Asia,” he said.

Dong Energy, EconGas, Uniper, Shell and Eneco hold Gate capacity but around 0.9 billion cubic metres remains available. Unlike the last four years, import capacity at Gate and other northwest European terminals is becoming more valuable in response to the start of US LNG exports.

“As more people are looking to Europe the capacity value has increased, whereas in other areas it’s quite the contrary. Everybody was hoping for Asia demand but there demand was slower so I think capacity value has decreased there,” he said.




In 2013, Qatargas signed a five-year deal to supply 1.14 million tonnes a year (mtpa) to Petronas’ half-share of the Dragon terminal at Milford Haven.

Qatargas 4, a joint venture between Qatargas and Royal Dutch Shell, signed the deal with Petronas, followed by a five-year agreement with E.ON Global Commodities to ship 1.5 mtpa to the Gate terminal.

Both deals are flexible, according to the original announcements, meaning Qatar is not obliged to ship any LNG to Britain or the Netherlands and can divert cargoes at will.

At the time, companies with import rights at Dragon and Gate were eager to drum up business and

effectively gave Qatar free options to make use of their capacity.

While Qatari deliveries to Dragon Gate have been rare up to now, weak Asian demand coupled with surging supply makes Europe an

increasingly attractive destination for cargoes.

Talks between Petronas and Qatargas over expanding the existing deal at Dragon initially sought to double volumes and extend the duration of the deal by up to 10 years, one of the sources said.

A proposal was also made to commit Qatargas to delivering a third of the overall volume, he said.At Gate, the choices boil down to exacting supply guarantees from Qatargas or making it pay for optional import slots, sources said.

Located near Milford Haven in Wales,

Dragon LNG is a major import terminal

for the supply of LNG to the UK and

consists of LNG receiving, storage,

regasification, flaring and send-out

facilities.




Oman: OOCEP plans to spud pilot well in Block 65 Oman Obvesver - Conrad Prabhu

Oman Oil Company Exploration & Production LLC (OOCEP), the wholly owned upstream oil and gas subsidiary of Oman Oil Company (OOC), says it is preparing to spud a pilot well in Block 65 in north Oman as part of a ‘Pilot and Appraisal Study Agreement’ signed with the Ministry of Oil & Gas last year.

Covering an area of around 1,230 sq km, Block 65 is surrounded by major oil and gas fields that produce from shallow cretaceous formations, namely the Natih and Shuaiba formations, with deeper opportunities in Mafraq, Khuff, Gharif, Barik and Miqrat formations. Petroleum elements in the acreage are proven for multiple play concepts.

According to OOCEP, the ‘Pilot and Appraisal Study Agreement’ signed with the government on May 31, 2015 calls for the drilling of one well to assess the prospectivity of unconventional resources in the

Block.

“Drilling site civil work has been completed and the rig has been mobilised to site. The spud of the pilot well is anticipated to take place during mid-March 2016,” OOCEP said in a report of the company’s operational performance during 2015. The study adds to OOCEP’s growing portfolio of upstream activities in Oman’s oil and gas sector.

Its flagship investment targeting the tight-gas Abu Butabul field in Block 60 in central Oman has been one of its crowning achievements. A major Gas Processing Plant commissioned in December 2014 began processing and exporting gas and condensate last year.

“Progressing towards achieving the plateau production of 70 million standard cubic feet per day (MMscfd), OOCEP successfully completed commissioning of 21 new wells, reaching a total number of 31 online wells in 2015,” the company said.

Block 42, a 22,590 sq km concession is also operated by OOCEP in the eastern part of the country, represents a frontier exploration domain, according to the company. Meanwhile, final commissioning of OOCEP’s Musandam Gas Plant project (MGP) in Musandam Governorate is ongoing with full operations due to commence this year, the company said. The plant, which is designed to process oil and sour gas, has been constructed at Tibat, not far from Ras Al Khaimah in the UAE.

An integrated gas pipeline has been supplying sweet gas from the Ras Al Khaimah Gas Plant to the MGP since June 2015. Offshore production capacity was also commissioned in July with well fluids from Block 8. OOCEP’s activities also include the management of investments in non-operated upstream assets in the Sultanate and abroad.




US: Scrambling for cover, U.S. shale producers ramp up hedging REUTERS - DEVIKA KRISHNA KUMAR

Struggling U.S. shale producers have scrambled to sell future output at their fastest pace in about six months in recent weeks, curbing a rebound in prices and potentially prolonging the oil market's worst rout in a generation, traders say.

As spot prices of crude rallied almost 60 percent from 12-year lows touched in mid-Feb, turnover in the long-dated oil contracts has soared to record highs, as producers started to lock in prices in the $40s, traders have said.

Turnover in the U.S. crude contracts for December 2017 surged to record highs of over 30,000 lots this past Friday while volumes in the December 2016 delivery touched an all-time high of nearly 94,000 lots.

Combined, that equates to almost 125 million barrels of oil worth over $5 billion, a small portion of overall daily volume in U.S. crude futures, but enough to catch traders attention.

One broker transacting deals for producers said it was the busiest he has been since October.

The hedging interest re-emerged in early February, but was limited to inquiries.

Now, brokers and traders say that has turned into execution, with some producers willing to hedge in the high $30s or low $40s in 2016 and between $45-50 next year, levels that are just about breakeven for many.

That is also below the $50 psychological threshold that many had thought would be necessary to prompt producers to seek price protection, suggesting drillers have accepted a new reality of lower-for-longer prices as OPEC pumps out record volumes and Iran's exports flood an already saturated market.

"Those that didn't take advantage of hedging in the past are likely more inclined to do it now, because the longevity of their business depends on it," said Tony Headrick, an energy market analyst at CHS Hedging LLC.

"The cost of production has declined to the point where at mid-40s they can hedge actively to remain viable."




Piling on hedges could prevent prices rallying through $45 a barrel while the extra protection may delay further U.S. production cuts, seen as key to eroding the glut that has pushed prices down 75 percent over 20 months, experts said.

In addition to output, hedging allows cash-strapped producers to also boost cash flow, critical to their survival.

HOPING FOR PROLONGED PROTECTION

The impact of the pickup in hedging activity was most conspicuous in longer dated oil contracts.

The 2017 WTI price strip has risen only about 15 percent over the past six weeks, much lower than the prompt contract's gains, while the selling has almost erased the far forward contract's premium over spot.

The contango, as the structure is known, narrowed to $5.82 on Monday, its lowest in almost nine months, and down nearly two thirds from about a month ago.

John Saucer, vice president of research and analysis at Mobius Risk Group in Houston, said he saw a "material" increase in producer hedging, with most action in this and next year's contracts, but extending through the whole of 2018.

Lack of forward buying by major consumers, like the airlines, has also meant prices have not received any boost as producers have been selling, adding to the pressure on prices.

Other factors have also contributed to the flattening curve, including short covering in the front month and output declines in the U.S.

DISTRESSED VS HOLDOUTS

To be sure, many hope for prices to go even higher. "If prices recovered to that range north of $60, we'll be seriously considering hedging," billionaire wildcatter Harold Hamm, who runs Continental Resources Inc, said on a conference call late February.

Sources said that many of the hedges in recent weeks have been banks mandating hedges for the next 18-24 months to put a floor on asset values. Morgan Stanley said in a note it has also seen "healthy" appetite for hedging from mid- and large-cap Permian producers, citing anecdotal evidence from the bank's trading desk.

In another sign of the prevalent hedging, net short positions among producers and consumers have jumped to record highs in recent weeks, data from the U.S. Commodity Futures Trading Commission (CFTC) shows.




NewBase 23 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 holding after API stockpile build reasserts glut concerns Reuters + NewBase

Oil prices fell in early Asian trading on Wednesday after figures from an industry group showed U.S. crude stockpiles rose last week more than expected, reinforcing concerns that supply continues to exceed demand.

The front-month contract in U.S. crude futures was down 40 cents at $41.05 a barrel by 0328 GMT. It struck a 2016 high of $41.90 in the previous session before closing at $41.45. The contract has rebounded 58 percent since hitting its lowest level since 2003 in February.

Brent crude was 39 cents lower at $41.40, reversing gains in the previous session when it finished at $41.79. Brent has surged 53 percent since hitting a multi-year low in January of $27.10 a barrel.

Oil price special

coverage




"Net supply in the short-term should still be in excess and thus brings us to believe that the current uptrend is unsustainable," said Phillip Futures Analyst Daniel Ang in a note on Wednesday.

The American Petroleum Institute (API), an industry group, said in a report after Tuesday's oil market settlement that U.S. crude stockpiles rose 8.8 million barrels last week to reach a record high of 531.8 million.

The stockpile growth reported by the API was 5.7 million barrels higher than estimates from analysts polled by Reuters. Official crude inventory data from the U.S. government will be released later on Wednesday.

The official U.S. data is likely to show that oil inventories rose to a record high for a sixth straight week, while oil product stockpiles probably fell, a Reuters survey showed.

"Near-term direction is likely to center on the degree of increase in U.S. stockpiles," ANZ bank said in a note on Wednesday.

Adding to the glut is the revival of Iranian barrels on the international market after sanctions were lifted in January.

Iran's crude oil exports have risen to 2.2 million barrels per day (bpd) since sanctions were lifted, an increase of 900,000 bpd, a senior official was quoted as saying on Tuesday.

"Until January we could only export 1.3 million barrels of oil but two months after the (lifting of) sanctions we are exporting 2.2 million barrels of oil per day," Vice President Eshaq Jahangiri was quoted as saying by the Shana agency.

Iranian flows may also increase as ship insurers have stepped in to plug a shortfall in cover for transporting Iranian oil resulting form the fact that U.S. reinsurers are still restrained by U.S. sanctions, according to officials involved in the initiative.




OPEC expects upsurge in oil prices with or without Iran Crude prices will rise to a “moderate level” even if Iran joins the Russian-Saudi production freeze at a later date, predicts the Organization of the Petroleum Exporting Countries (OPEC).

The world’s leading oil producers, including non-OPEC members, are meeting on April 17 in Doha, Qatar to discuss the output freeze.

While Iran is seeking to increase production with the lifting of international sanctions, the deal may be successful even without Tehran, according to OPEC Secretary General Abdalla Salem el-Badri.

"I hope the result of the meeting will be positive. They [Iran] are not objecting to the meeting but they have some conditions for the production and maybe in the future they will join the group,” he said at a conference in Vienna on Monday.

“The price is going up; I hope this trend will continue… I don't expect the price will go high but I think it will go to a moderate level," el-Badri added. According to el-Badri, while inventories are about 300 million barrels above the five-year average, prices will come back to normal, when the glut reduces. He added it’s too early to discuss a production cut, as producers should deal first with the freeze. "Let us go to the freeze and see what will happen, then we will talk about any other steps in the future," el-Badri said.




El-Badri’s words briefly bolstered oil prices, but the effect soon wore off. After the terrorist attacks in Brussels, Brent and US WTI benchmarks slightly lost momentum, trading at just over $41 per barrel.

Iranian Oil Minister Bijan Namdar Zanganeh has said Tehran will not join a production freeze until its output reaches four million barrels per day. Currently it stands at 2.8 million bpd.

SABIC: Oil market reaching point of "stability" CNBC - Huileng Tan

Oil markets may be about to reach some stability after a torrid run that pushed prices to their lowest level in over a decade, the vice chairman and acting chief executive of Saudi petrochemicals giant, SABIC said Wednesday.

Yousef Al-Benyan told CNBC on the sidelines of the Boao Forum for Asia that while this year and 2017 will be challenging for the industry, the outlook for 2018 and beyond is optimistic. "Of course, prices are not really at levels where we wish (them to be) but that's normal in a cyclical market," Al-Benyan said, adding that he expects crude oil at $60 a barrel by the end of 2016.

"A lot of people think that when crude oil price is up, it gives you much better returns on investment...(but) stability is very important not only for us as a producer but also for the customer and that's our main focus at this point."

Both U.S. WTI and European Brent crude oil prices are about 1 percent lower above $41 a barrel in Asian hours after Tuesday's deadly attacks in Brussels but are still higher than the 13-year-lows hit earlier this year.

"(Prices are) driven by global markets, not manipulated by one group, it's a supply and demand situation," he told CNBC from Hainan island inChina. Rather that fixating on feedstock prices, Al-Benyan said the company is focused on internal inefficiencies, external opportunities and serving customers effectively.

While economic growth is slowing in China, Al-Benyan said SABIC will stay the course as its sales volumes are still healthy.




NewBase Special Coverage

News Agencies News Release 23 March 2016

Drillers Can't Replace Lost Output as $100 Oil Inheritance Spent Bloomberg - Rakteem Katakey

For oil companies, the legacy of $100 crude is starting to run dry.

A wave of projects approved at the start of the decade, when oil traded near $100 a barrel, have bolstered output for many producers, keeping cash flowing even as prices plummeted. Now, that production boon is fading. In 2016, for the first time in years, drillers will add less oil from new fields than they lose to natural decline in old ones.

About 3 million barrels a day will come from new projects this year, compared with 3.3 million lost from established fields, according to Oslo-based Rystad Energy AS. By 2017, the decline will outstrip new output by 1.2 million barrels as investment cuts made during the oil rout start to take effect. That trend is expected to worsen.

“There will be some effect in 2018 and a very strong effect in 2020,” said Per Magnus Nysveen, Rystad’s head of analysis, adding that the market will re-balance this year. “Global demand and supply will balance very quickly because we’re seeing extended decline from producing fields.”




A lot of the new production is from deepwater fields that oil majors chose not to abandon after making initial investments, Nysveen said in a phone interview.

Royal Dutch Shell Plc is scheduled to start the Stones project in the Gulf of Mexico’s deepest oil field this year after approving it in May 2013. Benchmark Brent crude averaged $103 a barrel that month compared with about $41 on Monday. Stones will add about 50,000 barrels a day to Gulf of Mexico output at a peak rate, according to Shell.

Two other deepwater projects, run by Noble Energy Inc. and Freeport-McMoran Inc., are due to commence this year, the U.S. Energy Information Administration said in a Feb. 18 report. Anadarko Petroleum Corp. started the Heidelberg field in January.

That will help boost production in the Gulf of Mexico by 8.4 percent this year to a record annual average of 1.67 million barrels a day, according to the U.S. Energy Information Administration.

Eni SpA, Italy’s largest oil company, started the Goliat field in the Arctic this month and Shell began producing from a new area of the BC-10 project in Brazil on March 14. British driller Tullow Oil Plc plans to begin output from the Tweneboa-Enyenra-Ntomme field offshore Ghana in July or August.

“There is a wide range of upstream projects coming online in 2016, and that is a function of the high levels of investment deployed back when we were in a $100 a barrel world,” said Angus Rodger, a Singapore-based analyst at energy consulting firm Wood Mackenzie Ltd. “In the short term, they will generate far lower returns than originally envisaged.”

Yet, these developments won’t be enough to counter the natural decline in oil fields that are starting to suffer from lower investment. A little more than a year after Shell approved the Stones project in 2013, oil prices began their slump, with Brent dropping to a 12-year low below $28 a barrel in January.




That has squeezed budgets of oil producers and project approvals have dwindled. From 2007 to 2013, companies took final investment decisions on an average 40 mid- to large-sized oil and gas projects a year, Wood Mackenzie’s Rodger said. That fell to below 15 in 2014 and to less than 10 last year. Neither Rodger nor Rystad’s Nysveen expect an upturn this year. Project Approvals

Morgan Stanley estimates nine projects are in contention to get the green light this year, including BP’s Mad Dog Phase 2 in the Gulf of Mexico and Eni SpA’s Zohr gas field in Egypt. These are among 232 projects, excluding U.S. shale, awaiting approval following deferrals over the past two years, according to a Jan. 29 report.

Companies cut capital expenditure on oil and gas fields by 24 percent last year and will reduce that by another 17 percent in 2016, according to the International Energy Agency. That’s the first time since 1986 that spending will fall in two consecutive years, the agency said Feb. 22.

“We see oil investments are declining substantially,” IEA Executive Director Fatih Birol said in Berlin on March 17. “That we’ve never seen in the history of oil.”

Even after reducing costs for conventional projects by an average of about 15 percent last year, many still aren’t competitive, Wood Mackenzie’s Rodger said. Shell approved the Appomattox oil field in the Gulf of Mexico last year at a break-even oil price of $55 a barrel, still almost $15 above current market rates.

“The industry has had a real reset, with costs coming down and break-even prices for projects falling,” said Brendan Warn, a managing director at BMO Capital Markets in London, said by phone. “But costs will have to come down further.”




Fiscal deficit of Gulf economies to widen on low oil prices Gulf News + Gulf Times

The fiscal deficit in the Arabian Gulf region is expected to widen to 12.5 per cent of regional GDP this year, as low oil prices eat into government revenue, according to the ratings agency Moody’s. The fiscal deficit will widen from 9 per cent last year as the international oil benchmark, Brent, has lost nearly 65 per cent of its value to about US$41 per barrel since mid-2014.

“Lower public spending is likely to weigh on economic growth in 2016, although we expect it to remain positive as oil production is sustained and expenditure cuts are implemented only gradually," Mathias Angonin, an analyst at Moody’s, said in a report.

“However, lower oil prices will also affect GCC public finances, eroding their fiscal reserve buffers and increasing debt levels. We also increasingly view the GCC as a two-tier region."

Gulf governments last year dipped into bank deposits, tapped their foreign reserves and sold local bonds to meet their fiscal needs amid a sharp drop in oil prices. Some countries, including Saudi Arabia, have indicated that they plan to tap the international bond market this year to help plug their fiscal deficits.

This month, Moody’s put Kuwait, Saudi Arabia, the UAE, Bahrain, and Qatar under review for a cut. The rating for Bahrain was downgraded and also placed on review

Oman was cut for the first time by Moody’s last month and the rating is also under review for a further downgrade.




Moody’s expects the fiscal deterioration in Saudi Arabia, Bahrain and Oman to be faster than in the UAE, Qatar and Kuwait because of the ample reserves that the last three countries have, which will give them time to adjust to a low oil price environment.

Government debt is also forecast to rise to finance the fiscal deficit as financial assets drop, with a projected increase in external debt.

Moody’s projects Bahrain and Oman to have the biggest increase in government debt-to-GDP, which is forecast to rise to 35, and 18 percentage points this year from 2014 levels.

The ratings agency expects medium-term reforms will contribute “to relieving pressure on government balance sheets and will determine GCC sovereigns’ fiscal trajectory".

Gulf governments have resorted to spending cuts, removal of energy and

electricity subsidies and other reforms to cope with the low oil price environment.

They plan to introduce a value-added tax (VAT) in 2018.

Moody’s estimates that savings in the Gulf from increased fuel prices and VAT will average 2.5 per cent of GDP.

The reduction of subsidies on electricity and energy prices in the Gulf region will also help utilities improve their standalone credit rating, Moody’s said.

“The low oil price environment could potentially lead to utilities facing higher funding costs in the future if bank lending were to become constrained," Julien Haddad, a Moody’s analyst, said in a separate report. “However, it is also adding momentum to existing efforts that are likely to improve GCC utilities’ standalone credit quality over time."

The opportunity cost – the difference between a benchmark price, such the US price and the domestic energy price, scaled by consumption volumes – for the Gulf region was 5.2 per cent of GDP last year.

In addition, the Gulf is one of the largest per capita consumers of energy.

Gulf countries consumed 9.2 tonnes of oil equivalent (TOEs) per capita in 2014, as compared with a world average of 4 TOEs per capita, according to the IMF.

“We expect firms to benefit from greater operating efficiencies, which along with the tariff hikes could lead to a rationalisation of power consumption in the region and enable companies to enhance their capital expenditure planning," Mr Haddad said.

Oman has the highest subsidies for residential consumers of electricity and Dubai the lowest, based on the actual cost per kilowatt hour, according to Moody’s.




Moody’s says Qatar could hike electricity tariff

Qatar could increase the electricity tariff by 81% and 40% for residential and commercial connections respectively to reflect the actual cost per kilowatt hour (kWh), according to global credit rating agency Moody's. In Qatar, the average tariff for the residential and commercial connections are 2.3 cents per kWh and 3 cents per kWh respectively while cost is 4.2 cents per kWh, Moody's said in a report. As part of subsidy reforms in Qatar, a slab tariff system was introduced in October 2015 with the highest electricity and water usage tariff almost 120% and 130% higher than prior period respectively, it said, adding that Doha had also hiked fuel price by 30% to QR1.3 per litre in January this year.

"Qatar and Oman have the highest tariff subsidies for residential electricity consumers," Moody's said, suggesting broader subsidy reforms in the Gulf Cooperation Council (GCC). The credit implications are "neutral" in the short term for power and water generators that operate under unbundled systems, such as Qatar Electricity and Water Company as it will not directly benefit from tariff increases. This is because they have stable operating cash flow streams that are derived from secure, long-term purchase agreements with a sole off-taker. In the case of QEWC with Qatar General Electricity and Water Corporation (Kahramaa) for power and water, it added. In Oman, the electricity tariff has to be more than doubled with average tariff amounting to 4.1 cents per kWh, while cost is 8.4 cents per kWh.

In Saudi Arabia, the estimated tariff increase required for cost reflective level is 11% as average tariff is 3.7 cents per kWh and cost at 4.1 cents per kWh. In Abu Dhabi, electricity tariffs have to be increased 10% and 102% for residential and commercial connections respectively as the tariffs are 8.1 cents and 4.4 cents per kWh against the cost of 8.9 cents per kWh.




Dubai has the lowest subsidies in the electricity sector as s average tariffs and costs are 8.6 cents per kWh.

Finding that the GCC governments are reforming subsidies, including for electricity and water; Moody's expects this to continue as they seek to bolster government finances dented by the downturn in global oil prices, which are unlikely to shift "significantly" in 2016 from their early 2016 levels with Brent crude expected to average $33 per barrel in 2016 and $38 in 2017. "Although rated state-

controlled GCC utilities could face some short-term risks, we view these reforms and other changes they are likely to spur as a long-term credit positive for the sector overall," it said. The low oil price environment is adding momentum to existing efforts that are likely to improve the GGC utilities' standalone credit quality over time, it said, adding these include improvements in operating efficiencies, which along with the tariff hikes, could lead to a rationalisation of power consumption in the region and enable companies to enhance their capital expenditure planning. "We also expect to see greater participation by the private sector in the electricity industry across the GCC," it said, adding while independent power producers and independent water and power projects represent an important share of generation in Oman, Abu Dhabi and Qatar, they currently play a minor role in Saudi Arabia, the region's largest electricity market where they have less than 20% of total power generation, and in Dubai. However, GCC utilities -- which will remain of "strategic" importance to governments in the region -- could face some short-term risks; Moody's said the current macro-environment in the GCC could potentially lead to utilities facing higher funding costs in the future if bank lending were to become constrained. "The need for GCC governments to balance their accounts could prompt unfavourable policy or regulatory changes that affect the utilities sector, although we think this is unlikely at this stage," it added.




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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.

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NewBase 23 March 2016 K. Al Awadi

New base 814 special 23 march 2016

Business

Transcript of New base 814 special 23 march 2016