New base 1000 special 14 february 2017 energy news

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NewBase 14 February 2017 - Issue No. 1000 Senior Editor Eng. Khaled Al Awadi

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

UAE: Hawk Energy LLC Celebrate the issue number 1000 of the NewBase energy news

In behalf of Hawk Energy LLC, UAE, present to all our readers the issue no. 1000 of our energy news and we wish all prosperous future. We hope that you continue to be in our list for the longest and we promise you as long we are a round to keep presenting you the latest news and analysis in the energy sector, covering the MENA area and the world related energy news to our region.




UAE energy sector will Benefits from electric vehicles in downstream The national + NewBase

The adoption of electric vehicles (EVs) will eventually allow more crude to be used for export and for value-added petrochemical products, supporting the diversification efforts of oil-producing countries such as the UAE.

There were more than 1 million electric cars on the road in 2015, according to the International Energy Agency.

Yet there is a growing disconnect between what car makers and oil majors say, according to Colin McKerracher, the head of advanced transport at Bloomberg New Energy Finance (BNEF). Oil majors agree that the EV market will grow but assert that it will not have any real effect on demand over the next 20 years. However, car maker timelines are more aggressive.

"Most automakers now agree that EVs will play a major role in their vehicle line-ups. That is increasingly at odds with what several of the global oil companies say," Mr McKerracher said, adding that someone was going to be wrong to the tune of billions of dollars.

A major part of this expansion is a result of Elon Musk’s company Tesla, which yesterday announced its launch in the UAE. "What Tesla has done has dragged the timeline forward for other car makers investing significantly in electrification," said Mr McKerracher.

BNEF puts EV growth rates at between 40 and 60 per cent year-on-year, but it will take close to another decade for the hydrocarbon sector to be affected.

"There’s definitely an impact coming from EVs on oil demand, but it’s not as soon as some EV enthusiasts would hope," he said.




Mr Musk said that he agreed that EVs are still an emerging technology.

"EV will happen slower than self-driving vehicles, the transition to EVs will take about 40 years," he said yesterday at the World Government Summit in Dubai.

But when that time comes, it can be a win-win for oil-based economies. The amount of fuel that is displaced as a result of EVs can allow more oil for export or even help to increase the downstream sector’s product offerings, such as high-value petrochemicals.

Mr McKerracher said that the biggest wild card will be if India’s transport system begins to lean to more electric in the 2020s, which will have a more dramatic impact on the oil market.

He said: "Once that starts, the producers and refiners who have optionality in what they can do with their resources – for instance, push more in petchems – they’ll have an advantage."

Alan Gelder, the energy consultancy Wood Mackenzie’s vice president for refining, chemicals and oil markets, said that EVs have the potential to significantly reduce future petrol demand if there is a technology breakthrough.

"The opportunity for petrochemicals could be large, [with] global gasoline demand of almost 25 million barrels per day," he said. "Large-scale EV penetration could be disruptive to the outlook for petrochemical feedstocks."




Saudi Is Turning to Wind and Solar Power, to save burning oil Bloomberg -Anthony Dipaola

The nation most identified with its massive oil reserves is turning to wind and solar to generate power at home and help extend the life of its crucial crude franchise.

Starting this year, Saudi Arabia plans to develop almost 10 gigawatts of renewable energy by 2023, starting with wind and solar plants in its vast northwestern desert. The effort could replace the equivalent of 80,000 barrels of oil a day now burned for power.

Add in natural gas projects set to start later this decade, and the Saudis could quadruple that number, according to Wood MacKenzie Ltd. That could supplant all the crude burned in the kingdom during its winter months.

The effort goes hand-in-hand with a drive by the royal family to broaden the economy following two years of budget deficits tied to low oil prices. More industry, though, means more energy, with the amount of power used at peak times growing by 10 percent in the last year alone.

“Renewable energy is not a luxury anymore,” said Mario Maratheftis, chief economist at Standard Chartered Plc., in an interview. "If domestic use continues like this, eventually the Saudis won’t have spare oil to export.’’

In all, Saudi Arabia is seeking $30 billion to $50 billion worth of investment in renewables, Energy Minister Khalid Al-Falih said this month. The ministry will set up a division to handle the tenders until the country establishes a new independent buyer for all power supplies.

“The terms on renewable contracts will be motivating so that the cost of generating power from these renewable sources will be the lowest in the world,” Al-Falih said at a news conference in Riyadh. The kingdom will award its first tenders to build 700 megawatts of solar and wind energy in September, Al-Falih said.




Energy Pricing

The government has already raised domestic energy prices to slow demand growth and called for greater efficiency, according to the Riyadh-based King Abdullah Petroleum Studies and Research Center. Failing to tap more sources, including renewable energy, natural gas or even nuclear reactors could erode the oil exports still vital to the economy, the center wrote in an October report.

Improving the country’s energy efficiency by just 4 percent a year could save the equivalent of 1 million barrels a day of crude by 2030, according to the report.

The cornerstone of an economic transformation plan championed by Deputy Crown Prince Mohammed bin Salman, a son of the king, is the sale of as much as 5 percent of Saudi Arabian Oil Co. With the company worth about $2 trillion, according to estimates from the prince, the share sale would be the worlds’ largest initial public offering.

The kingdom, OPEC’s biggest member, is the linchpin of the group’s effort to prop up crude prices by cutting output to reduce a global supply glut. Saudi Arabia said it cut production by 717,600 barrels a day last month, its biggest cut in more than eight years, to 9.748 million a day, according to a monthly report from the Organization of Petroleum Exporting Countries.

Aramco Plants

Saudi Aramco, as the state energy producer is known, already earns most of the Persian Gulf kingdom’s income by pumping 1 in every 10 barrels sold every day. It’s also driving the country’s first steps toward a renewable energy industry.

At its sprawling campus of office buildings, control rooms and suburban-style residential compounds in Dhahran in the country’s east, Saudi Aramco runs the country’s biggest solar plant, a 10 megawatt facility mounted on a parking lot roof.

In January, it started the kingdom’s first commercial wind turbine to power a facility in the northwest. The solar panels atop the parking facility cut the need for the equivalent of about 30,000 barrels of oil and the wind turbines will eliminate demand for about 19,000 barrels, according to Aramco.

As the kingdom strives to build industries and spread jobs, other state companies are expanding projects. The Saudi Arabian Mining Co. operates a phosphate plant and is building a new industrial city in the northwest. Power for sections of the vast area where those projects are located will partly come from renewables and new gas projects.

“Small projects are very important in helping diversify the country’s energy sources,” Stewart Williams, Wood Mackenzie’s vice president for Middle East research said in a telephone interview. “These are steps toward building up the country’s energy base.”




Without alternative power sources, including gas and renewables, the kingdom would be forced to increase its crude burn. That can reach as high as 900,000 barrels a day during the kingdom’s summer months, according to data from the Joint Organisations Data Initiative.

Saudi Arabia has already taken steps to substitute natural gas for oil in power plants, a change that’s had “immense” impact on the crude burn, OPEC said in its Monthly Oil Market Report released in January. The use of crude for domestic power has fallen by nearly a third since the Wasit gas plant began operations in March 2016, according to the OPEC report.

300,000 Barrels

Saudi Aramco will bring online the similar-sized Fadhili gas project in the country’s east by the end of the decade. That gas project and the renewable projects planned for completion by 2023 could save about 300,000 barrels of oil from being burnt for power, according to estimates based on IEA and OPEC data.

Alternative energies are “a key factor in the economic transformation,’’ Fabio Scacciavillani, chief economist of the Oman Investment Fund, said in an interview. “This region has a great competitive advantage in low-cost energy production and that will continue with renewables. That will create a big advantage particularly in energy intensive industries.’’




Lebanon should relax bidding conditions to benefit from any deepwater gas finds.. Robin Mills is CEO of Qamar Energy, and author of The Myth of the Oil Crisis.

Snow fell across Lebanon over the New Year, and power cuts plunged towns in the Bekaa valley into darkness. Syrian refugees in Akkar huddled in their tents. Meanwhile, as Egypt and Israel forge ahead with developing their offshore gasfields, the inviting Mediterranean waters seem to hold the elusive solution to the country’s energy and economic woes.

Lebanon thinks the time has come for its own deepwater gas wealth. The election in October of a new president, Michel Aoun, after an interregnum of more than two years, has permitted the passage of two crucial decrees enabling exploration bids. Eni’s giant Zohr find off Egypt, less than 300 kilometres from Lebanese waters, has raised optimism about the area.

Beirut has divided its offshore into 10 blocks. Five will be offered in the initial round, with a deadline in September – numbers 8, 9 and 10, along the disputed maritime border with Israel, block 1 on the Syrian frontier in the north, and block 4 in the middle.

The bidding conditions are stringent. Applicants to lead a consortium have to have US$10 billion of assets and to operate at least one deepwater petroleum project. Qualification for a lesser role requires US$500 million of assets and established oil or gas production.

Companies that qualified for the last, abortive round in 2011 include some impressive contenders – Shell, ExxonMobil, Chevron, Statoil, Total, Eni and others. Qualified non-operators featured the UAE’s Dragon Oil, Crescent and Dana Gas alongside a slew of local, Japanese, Russian, Turkish and other companies.

But Lebanon’s ambitions face three serious problems: low oil and gas prices; politics; and the difficulty of marketing gas.

The business environment is very different




from 2011, when the world’s largest oil companies were sufficiently intrigued by Lebanon’s potential to qualify. Then, global LNG prices averaged about $15 per million British thermal units; today, even helped by high winter demand, they are at about $9 and a further glut is on the way.

With the steep drop in oil prices, several of those previously qualified have gone bust, been taken over, or their assets have declined below the required limit. Others, conserving capital or concentrating on shale in North America, will not be interested in exploring hitherto untested waters up to 2,100 metres deep. Some Lebanese politicians act as though they can already spend the gas revenues; there is a real risk there may be nothing to find.

The continuing war in Syria does not encourage investors to come to the region. Even more seriously, Lebanon has lost credibility after the long political stalemate that stymied the last bid round. In Israel, gas production was severely delayed by changes in tax and monopoly rules, and populist pressure.

Oil companies will ask if they will invest millions of dollars in exploration, perhaps hundreds of millions in drilling wells, only to have development prevented by gridlock in the factionalised Lebanese politics. They will also be worried about the disputed borders of all the blocks except No 4.

Lebanon is a small gas market, yet only large offshore finds will be commercial. Pipelines to take surplus gas to consumers in Turkey will have to cross the disputed waters of Cyprus, which wants to export its own gas, or across the seabed of war-torn Syria. Or perhaps, in partnership with Cyprus, gas could flow south to Egypt.

Lebanon needs companies with the financial and technical strength to take on these challenges. But at the same time, it should not raise the bar too high and discourage hungry, capable mid-size players. The more competitive the bidding, the more likely it is to get a good deal and move quickly on to discovering whatever resources its waters hold. Only if it can then negotiate squabbling local factions and the intricacies of regional geopolitics will the residents of Lebanon gain some benefits.




Iraq: Genel Energy update on Miran and Bina Bawi fields Genel energy

Genel Energy has announced that the Company has finalised documentation of previously agreed terms of Amended and Restated Production Sharing Contracts ('PSC's) and Gas Lifting Agreements ('GLA's) for both the Miran and Bina Bawi gas fields.

The Amended and Restated PSCs and GLAs for Miran and Bina Bawi incorporate the commercial terms as announced in the term sheets signed in 2015 by Genel and the Kurdistan Regional Government ('KRG').

With the PSC and GLA terms formally confirmed, Genel will now be able to progress the project. The Company remains committed to developing these large scale, low-cost, onshore gas fields, which will form the cornerstone of gas exports to Turkey under the 2013 KRG-Turkey Gas Sales Agreement.

The GLAs contain conditions precedent, which, inter alia, include the execution of final agreements on the midstream gas processing facilities and pipeline transportation, the execution of the financing documents and the completion of updated competent person's reports for Miran

and Bina Bawi.

Both Genel and the KRG have the option to terminate the GLAs by February 2018. If the conditions precedent are not satisfied within 12 months, the KRG has a right to terminate the GLAs. In the event of termination, and a subsequent failure to conclude new gas lifting agreements within one year period, the KRG can also terminate the Miran and Bina Bawi PSCs. During the three year period following such a termination, Genel would have a right of first refusal to participate in the development of the Miran and Bina Bawi gas fields with a 49% working interest on the same terms offered to any third party.

Murat Özgül, Chief Executive of Genel, said:

'We are very pleased to have signed definitive agreements for our gas project and are now focused on the next step of concluding negotiations with potential partners, and moving the gas project towards the FID. We are determined that 2017 will be a watershed year as we seek to create a gas business that will be transformational for both Genel and the KRG.'




Norway's oil minister officially opens Aker BP's Ivar Aasen field Source: Aker BP

Norway's Minister of Petroleum and Energy Terje Søviknes has officially opened Aker BP's Ivar Aasen field in the North Sea. 'The development of Ivar Aasen is an important milestone for the oil industry, and represents significant values for the Norwegian society', said Søviknes at the opening ceremony, which was conducted on the helideck on the Ivar-platform. This was the minister’s first visit to an oil platform.

Oil production from the Aker BP-operated field started on 24 December 2016, four years after the Plan for Development and Operation (PDO) was submitted. The project has a total cost framework of NOK 27.4 billion. The development was completed on time and within budget – and with no serious incidents.

Ivar Aasen is a large and demanding project, with deliveries from all over the world. A total of more than 5000 people, primarily in Trondheim, London, Singapore, Arbatax (Sardinia), Stord and Oslo, have spent more than 17 million working hours on the Ivar Aasen project.

Norway's oil minister officially opens Aker BP's Ivar Aasen field

'Production start-up was a huge milestone for Aker BP as a company. This would not have been possible without skilled, safety-conscious employees and suppliers working closely together. We have achieved good results by working as a single team with a common goal – completely in line with our values', says Aker BP CEO, Karl Johnny Hersvik.

Modern technology contributes to maximum efficiency in operation of the field. The organisation on board the platform is closely integrated with the onshore organisation via modern




communication solutions. Operations are controlled from an operations centre in Trondheim. Core offshore staffing during normal operations will consist of 21 people.

'We are building a strong, cost-effective Aker BP, whose goal is to become a standard-setting company on the Norwegian Shelf. Ivar Aasen has been organised, and will be operated, in a way that is completely in line with this strategy,' Hersvik points out.

The recoverable reserves for the Ivar Aasen project are estimated at more than 200 million barrels of oil equivalents. The field’s economic lifetime could be 20 years, depending on oil prices and production development.

Aker BP, which was established on 30 September 2016 following the merger of Det norske oljeselskap and BP Norge, has the vision of becoming the leading independent offshore exploration and production company. The company has activities and ownership in licences along the entire Norwegian coast, from the southern part of the North Sea to the Barents Sea. 'Aker BP has considerable confidence in the Norwegian Shelf as an attractive area for investment. This applies within exploration, field development and, not least, operation and further development of the fields where we are the operator. In this landscape, start-up of production on Ivar Aasen is an important source of inspiration for us,' says Øyvind Eriksen, chairman of the board in Aker BP and CEO in Aker.

Facts about the Ivar Aasen field

• The Ivar Aasen field is located in the North Sea, approx. 175 km west of Karmøy.

• The field was discovered in 2008, and was assessed together with previous discoveries in the nearby area.

• In December 2012, Det Norske submitted a plan for development and operation of the Ivar Aasen field to the Ministry of Petroleum and Energy (MPE). The Storting (Norwegian Parliament) approved the plan on 21 May 2013.

• The first oil was produced on 24 December 2016 – on time and within the budget.

The Ivar Aasen field is a coordinated development with the Edvard Grieg field, which is located 10 km further southeast, and the export solutions are coordinated with this field. The gas is exported via the UK Shelf. The oil from the two fields is exported through a new pipeline from the Edvard Grieg field to the Grane oil pipeline, and further on to the Sture terminal. Ivar Aasen receives power from the Grieg platform.




Sri Lanka launches tender to develop the M2 gas block in the Mannar Basin Source: PRDS

The Sri Lankan government is inviting expressions of interest for partners to undertake the appraisal and development of gas discoveries and prospects in the 2,924-sq km offshore (ex-Cairn SL 2007-01-001, aka Block 2) Block M2, in the Mannar Basin. The block will be offered for licensing this year, including the Barracuda and Dorado gas-condensate discoveries. A data package will be available containing well data and some 2,600 sq km of 3D seismic coverage.

The remainder of Sri Lankan acreage will be released in a bid round in 4Q ’17. WesternGeco is planning 2D and 3D spec seismic ahead of this off the East coast and in the Mannar Basin. Some airborne FTG/mag surveying is also planned. Govt officials will be available for private meetings in Houston (5-9 Mar ’17) and London 13-14 Mar ’17), and the Sri Lankan plans will also be discussed at CERAWeek on 7 March.

Expressions of interest to be emailed to the Director General of the PRDS, Saliya Wickramasuriya, [email protected], or [email protected].




US: Tight oil expected to make up most of U.S. oil production increase through 2040: U.S. Energy Information Administration, Annual Energy Outlook 2017 Reference case

EIA’s recently released Annual Energy Outlook 2017 (AEO2017) Reference case projects that U.S. tight oil production will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production.

After 2026, tight oil production remains relatively constant through 2040 in the Reference case as tight oil development moves into less productive areas and as well productivity decreases. Side cases with different resource and technology assumptions result in different tight oil and total U.S. oil production projections.

U.S. production of tight oil has increased significantly since 2010, driven by technological improvements that have reduced drilling costs and improved drilling efficiency in major shale plays such as the Bakken, Eagle Ford, and the Permian Basin.

Production from tight oil plays surpassed 50% of total U.S. oil production in 2015 when tight oil production reached 4.9 million per day (b/d). Tight oil production and overall U.S. oil production are expected to increase through around 2030 in the Reference case.

In the Reference case, tight oil production from the Eagle Ford and Bakken—two of the largest tight oil regions in the country—begins to decline after 2020 and 2030, respectively. Production in the Permian Basin (which includes the Austin Chalk, Spraberry, Avalon/Bone Spring, and Wolfcamp plays) remains relatively high through 2040.

Compared with the Eagle Ford and Bakken, the Permian Basin has more geographic extent and contains multiple stacked plays, providing drillers with more opportunities for continued long-term development.




Two side cases included in the AEO2017 analysis apply alternative assumptions regarding technological advances and resource availability, which lead to very different projections for tight oil production.

In the High Oil and Gas Resource and Technology case, which uses more optimistic technology and resource assumptions, tight oil reaches 11.0 million b/d by 2035, or 66% of total U.S. production, as higher well productivity reduces development and production costs, spurring additional resource development.

In the Low Oil and Gas Resource and Technology case, which applies more pessimistic technology and resource assumptions than in the Reference case, tight oil provides less than half of total oil production after 2030, and total U.S. oil production in 2040 is well below its current level.

Source: U.S. Energy Information Administration, Annual Energy Outlook 2017

Projected oil production in the United States is also sensitive to the path of world oil prices, as shown in two other cases. In the AEO2017 High Oil Price case, where world oil prices rise rapidly and are sustained at higher levels, oil production increases to 13.0 million b/d by 2021 before declining to 10.5 million b/d by 2040.

Despite reaching a higher production level faster, total cumulative production through 2040 is lower in the High Oil Price case compared with the slow but steady production increase High Oil and Gas Resource and Technology case. In the AEO2017 Low Oil Price case, sustained low prices lead oil production to fall below 8 million b/d by 2022 and to gradually decline to 7 million b/d by 2040.




NewBase 14 February 2017 Khaled Al Awadi

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

Oil rises on OPEC-led cuts, but market remains range-bound Reuters + NewBase Oil rose on Tuesday, supported by an OPEC-led effort to cut output, but rising production elsewhere kept prices within the narrow range that has contained them so far this year. Brent crude futures, the international benchmark for oil prices, were trading at $55.76 per barrel at 0112 GMT, up 17 cents from their last close. U.S. West Texas Intermediate (WTI) crude futures, were up 14 cents at $53.07 per barrel.

The gains followed 2-percent falls in the previous session. Both oil benchmarks have remained within a $5 per barrel trading range since the beginning of the year. "The usually fairly volatile oil price has barely budged for two months, the reason being conflicting dynamics in the market," said Dutch bank ABN Amro. The Organization of the Petroleum Exporting Countries (OPEC) and other producers including Russia have agreed to cut output by almost 1.8 million barrels per day (bpd) during the first half of 2017 in a bid to rein in a global fuel supply overhang. But undermining these efforts has been rising production in the United States, where increased drilling activity especially by shale oil producers has lifted overall output to 8.98 million bpd, up 6.5 percent since mid-2016 and to its highest level since April last year. "A floor is being formed by the production reduction agreed by OPEC and several non-OPEC oil producers ... At the other end of the spectrum, a ceiling is being created by the stepped-up shale oil production in the U.S.," ABN said.

Oil price special

coverage




Despite an OPEC compliance rate of around 90 percent with the announced cuts, scepticism remained over the end result. "OPEC producers want the market to believe they will stick to the agreed production freeze (cut). But lessons from the past have made the market deeply suspicious," ABN said. Traders also pointed out that even at an OPEC compliance of 90 percent, and a much lower rate for non-OPEC members, producers would have to accelerate their cuts in the coming months in order to achieve the average daily reduction target agreed for the first half of the year. ABN said it had reduced its average Brent oil price forecast for the first half of 2017 "from $55 per barrel to $50 per barrel, while allowing for a possible temporary dip towards $45 per barrel". PEC is urging oil suppliers outside the group to fulfill their commitments to cut output, and crude prices will rise once producers demonstrate better compliance with their agreement to clear a global glut, Kuwait’s oil minister said. The Organization of Petroleum Exporting Countries, which agreed to the cuts with 11 other oil-producing nations in December, is 92 percent compliant with its pledge to reduce output by 1.2 million barrels a day, Oil Minister Essam Al-Marzooq told reporters Monday in Kuwait City. Non-OPEC producers are complying at a lower rate of more than 50 percent, he said. “At the time when producers signed the deal, the initial commitments were to gradually increase cuts until April and May, so we were expecting to see some producers not fulfilling the 100 percent cuts,” Al-Marzooq said. “We understand the circumstances, and in February we are talking to non-OPEC producers to raise their cuts according to their commitments.” OPEC, faced with lower crude prices, agreed in November to reverse its strategy of pumping without limits to defend its share of the market against increased supplies, including oil from U.S. shale deposits. The group secured commitments from other producing states to pare their output by 558,000 barrels a day starting in January. Benchmark Brent crude, which traded at more than $115 a barrel in June 2014, has stemmed losses since the deal took effect and was trading 26 cents lower at $56.44 in London at 11 a.m local time.




NewBase Special Coverage

News Agencies News Release 14 Feb. 2017

Opecç Amazing and Shortlived Compliance By Julian Lee

Don't get your hopes up that the oil market's headed back to the future.

Ever since OPEC output quotas were introduced in the 1980s, Saudi Arabia has been the group's great leveler, making more than its share of production cuts when prices needed support, while remaining the only member with enough spare capacity to raise production in times of shortage.

That all changed in 2014. In November that year, oil minister Ali Al-Naimi said the Saudis would no longer cut output to support prices and subsidize high-cost rivals. His successor, Khalid al-Falih, only agreed last year to return to actively managing supply provided production cuts were collective and the burden was shared equitably.

Early evidence of actual cuts seems to show that the kingdom has resumed its old swing producer role, doing more than its share to cut output in the hope of rebalancing the oil market. But there's more to it than that.

Data published on Friday by the International Energy Agency show Saudi Arabia reduced its output in January by more than required under the November 2016 agreement. A cut of 560,000 barrels a day from the October baseline level was 14 percent more than the kingdom's pledged reduction of 490,000 barrels. That certainly looks like the behavior of a swing producer.

Unfair Shares

Saudi Arabia's apparent resumption of its swing producer role may prove premature

Note: Chart shows percentage of agreed cut made by each OPEC member in January Note: Iran, Libya and Nigeria were exempt from the November agreement on production cuts.




So how should we read that bigger-than-required output cut? It may be tempting to see it as a move by the kingdom to offset rising output from Libya and, to a lesser extent, Nigeria -- both of whom were exempt from cuts under the November deal. But I see it as a further indication that this may be as good as it gets for compliance with the deal -- a suggestion I raised last week.

When challenged on less-than-total compliance with previous output deals previous Saudi oil ministers invariably responded that it was the kingdom's average production level over the duration of an output deal that should be considered, not its compliance on a month-to-month basis. If this is their argument this time around -- and I see no reason to expect anything different -- then Saudi production should rise in the coming months.

From one perspective, this should come as little surprise. The kingdom derives its oil income from exports of the black stuff, not from domestic consumption, which is still heavily subsidized. The logical desire for Saudi Arabia is to cut its output with minimal impact on its exports. It can do this by concentrating the output cut in the period -- right about now -- when its domestic oil demand is lowest.

Oil use in the kingdom is highly seasonal, peaking in the hot summer months when soaring demand for electricity to run air conditioners has required as much as 900,000 barrels of crude to be burnt in power stations. The increase in demand usually begins in April or May, although last year it was as early as March.

To avoid making significant cuts to high-value oil exports in order to meet loss-making domestic demand, Saudi Arabia will need to boost output as consumption at home rises. Reducing output more than it needs to now gives it the flexibility to do just that, while still abiding by its commitment on an average basis over the six-month life of the deal.

Oil's Big Day

Data showing 90% compliance with OPEC cuts lifted Brent by about 80 cents in 10 minutes

Intraday times are displayed in ET.




Front-loading the cuts also gives an early impression that the kingdom, and OPEC collectively, are serious about rebalancing the market. And this is working. Crude oil prices jumped by around 80 cents a barrel immediately after the publication of the IEA data -- the biggest price response to the publication that I can remember in more than 25 years of studying the oil market.

At 90 percent, it looks like January may be as good as it gets for compliance. We may have another month or so before Saudi Arabia needs to choose between cutting exports or boosting supply, but it is difficult to see overall adherence getting much better without involuntary cuts somewhere due to accident or unrest.




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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 February 2017 K. Al Awadi




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