New base 805 special 10 march 2016

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NewBase 10 March 2016 - Issue No. 805 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: Adwea selects advisers for 350 megawatt solar park The National - LeAnne Graves

Advisers have been chosen for the 350-megawatt solar park in Abu Dhabi announced last year, according to industry insiders. Abu Dhabi Water and Electricity Authority (Adwea) has selected its financial, legal and technical advisers for the project to be built in Sweihan, about an hour’s drive east of the capital.

The lobbying firm Akin Gump Strauss Hauer & Feld has been chosen as the legal adviser. Alderbrook Finance will take the lead as financial adviser and Fichtner Consulting Engineering will be the technical adviser.

Fichtner, a German company, confirmed that it was appointed as technical adviser. The independent engineering consultancy is also involved in the third phase of the Mohammed bin Rashid Al Maktoum PV solar park, which will produce 800MW.

For the financial role, the big four financial advisers – Ernst & Young, PricewaterhouseCoopers, Deloitte and KPMG – were edged out by a boutique firm. That company, Alderbrook, is led by Bill Appleby, the former Citigroup head of project

finance in Europe, Middle East and Africa region. He confirmed the appointment.

Mr Appleby had a hand in Saudi Electricity Company’s independent power producer programme, which used the same scheme that the Sweihan project will operate under. He also helped the Moroccan Agency for Solar Energy (Masen) to develop several solar projects.

The legal adviser, Akin, has been involved in many solar projects,but none outside the Americas, according to its website. Akin could not be reached for comment yesterday.

The Sweihan solar park is to produce enough electricity to power more than 50,000 homes, with Adwea paying only for the net electricity supplied by the plant. The utility is to own 60 per cent of the project with the developer (which has yet to be selected) holding the remaining stake.

This will be Adwea’s first foray into the solar sector, and many companies are lining up to get a chunk, including regional firms such as Masdar and the Saudi companies Acwa Power and Abdul Latif Jameel.




Saudi Aramco to build more refinaries in India for MS Gulf News + Bloomberg + Reuters

The world’s largest crude exporter plans to invest in Asian refineries to ensure it has plenty of buyers in the fastest-growing region for fuel demand.

Saudi Arabian Oil Co. is adding India to the list of Asian countries where it plans to build new refineries as part of a plan to almost double its global refining capacity, Chief Executive Officer Amin Nasser told Bloomberg in Jubail, Saudi Arabia. Saudi Aramco, as the company is known, is also considering plants in China, Indonesia, Malaysia and Vietnam.

The Dhahran, Saudi Arabia-based company is considering expanding its refining capacity to find new outlets for Saudi crude oil, Nasser said on Tuesday in a speech during a Saudi refining conference in Jubail.

The company already owns a stake in a refinery in China’s Fujian province along with Exxon Mobil Corp. and China Petroleum & Chemical Corp. It’s still in talks with another partner, China National Petroleum Corp., to build a new joint-venture refinery. “Talks are good and ongoing,” he said.

Aramco has a refining capacity of around 5.4 million barrels a day now, and it will almost double that to between 8 million and 10 million, he said, without specifying a time frame for the expansion. Saudi Arabia produced 10.2 million barrels of oil a day in February, according to data compiled by Bloomberg.

Overseas refining investments

Saudi Arabia has 2.4 million bbl/d of refining capacity overseas through joint and equity ventures in

facilities in the United States, China (in Fujian Province with ExxonMobil and Sinopec), South Korea

(with S-Oil), and Japan (with Showa Shell).

Saudi Aramco’s share of overseas ventures is 0.9 million bbl/d. In the United States, Saudi Aramco

and partner Royal Dutch Shell own three Motiva joint-venture refineries in Louisiana and Texas. The

three facilities currently have a total capacity of about 1 million bbl/d.

Saudi Aramco owns 50% of Motiva through a subsidiary, Saudi Refining. According to the Middle East

Economic Survey, Saudi Aramco is expected to invest $100 billion domestically and overseas to

expand its refining capacity to 8-10 million bbl/d.

Planned domestic refineries or refineries under development include:

Yanbu Aramco Sinopec Refining Company (YASREF) Limited, a joint venture with Chinese

Petrochemical Corporation(Sinopec), will be able to process up to 400,000 bbl/d of Arab Heavy crude

oil from the planned Manifa oil development by the third quarter of 2014.

Saudi Aramco is developing its 400,000 bbl/d Jazan refinery project in southwest Saudi Arabia. It will

be able to process Arab Heavy and Arab Medium crude oil by late 2016.

Saudi Aramco is studying an expansion of its integrated Petro Rabigh Refinery and petrochemical

joint venture, which currently has a capacity of 400,000 bbl/d.




In Saudi Arabia, the company is now considering whether to add more petrochemical plants to its existing refineries. The company is close to finishing a petrochemical plant within its joint refinery with Japan’s Sumitomo Chemical Co Ltd in Rabigh. Aramco is also studying a similar plan at Ras Tanura, its largest refinery in Saudi Arabia, which has the capacity to refine 550,000 barrels of oil a day, Nasser said.

Saudi Aramco to double gas production in 10 years — CEO

Jubail, Saudi Arabia: Saudi Aramco plans to nearly double its gas production to 23 billion standard cubic feet per day in the next decade, its chief executive said on Tuesday. “The kingdom has managed to increase gas production from 3.5 billion standard cubic feet (scf) per day in 1982 ... to

more than 12 billion scf now and this figure is expected to double to around 23 billion scf during the coming decade,” Amin Nasser told an industry conference. “Work is under way to execute an ambitious plan to implement this during the coming 10 years,” he said, without detailing the plan.

Saudi Aramco, the world’s largest oil and gas company, has embarked on a massive programme to boost gas output for electricity and petrochemical production by developing gasfields not associated with oil production.

Saudi Arabia sends requests to banks for $6-8b loan -sources

Dubai: Saudi Arabia’s government has asked banks to submit proposals to extend it a five-year, US dollar loan of between $6 billion and $8 billion, with an option to increase the size, sources familiar with the matter told Reuters on Wednesday. Earlier this month, Reuters reported that Saudi Arabia had asked banks to discuss the idea of an international loan, but details such as the size and tenor were not specified. The sources declined to be named because the matter is not public. Calls to the Saudi finance ministry and central bank seeking comment on Wednesday were not answered.




Qatar Rasgas & CNPC renegotiate LNG price,as it’s below 5$/mmbtu Bloomberg + NewBase

China National Petroleum Corp, the nation’s biggest producer of oil and gas, is seeking opportunities to renegotiate the pricing method of its liquefied natural gas contract with Qatar, chairman Wang Yilin said in Beijing.

CNPC’s listed-unit PetroChina Co, which has a 3mn-tonne-a-year LNG contract with Qatargas that runs through 2037, is among buyers taking advantage of greater bargaining power gained from a glut of gas and tumbling prices.

RasGas agreed last year to renegotiate its contract with Petronet LNG Ltd, resulting in an immediate drop by almost half of the prices the Indian importer was paying.

“We have always been looking at price renegotiation opportunities on LNG term contracts, which is an international convention,” Wang said. “We are seeking proper time window of setting up a price renegotiation mechanism as we continue to execute the current contract.”

Rising demand for price renegotiation could unnerve LNG suppliers, according to Neil Beveridge, a Hong Kong-based analyst at Sanford C. Bernstein & Co. PetroChina is “racking up losses on LNG” despite lower prices, he said.

“With Petronet able to successfully re-negotiate prices, CNPC are now looking to do the same,” Beveridge said in an e-mail. “While each contract is different, this will certainly create nervousness among LNG suppliers who have spent vast sums of money on building LNG capacity.”

Asian spot LNG prices fell below $5 for the first time in January in data going back to 2010, according to New York-based Energy Intelligence. The price for LNG in Asia bought through long-term contracts, which are traditionally linked to oil, may fall to a low of about $4.10 per million British thermal units in June, according to a February 5 report from Credit Suisse Group AG.

The bank said in December that if Petronet successfully reworked its supply contract with Qatar then Korea Gas Corp and CNOOC Ltd may also seek to renegotiate LNG agreements.




Oman: Major Omani component needed in Oman wind-farm project Oman observer - Conrad Prabhu –

The Sultanate’s maiden wind-powered electricity generation venture will have a strong In-Country Value (ICV) component, according to the head of the Omani partner in the joint venture implementing this landmark project.

Eng Hamed bin Salim al Magdheri, CEO of Rural Areas Electricity Company (RAECO), which along with UAE-based Masdar, is executing the keenly anticipated project, said the successful bidder is obliged to accord priority preference to indigenous Omani goods and services in the implementation of the scheme.

“In-Country Value capture is an important objective of the project and is clearly articulated in the project scope and tender documents,” said Al Maghderi.

“The contractor is obligated to not only source locally manufactured goods, such as transformers, cables, building materials and so on, during the construction phase, but also train Omani technical staff who will take over operation and management of the plant over the long term,” he added in comments to the Observer.

RAECO, a wholly owned subsidiary of The Electricity Holding Company (Nama Group), along with Abu Dhabi’s renewable energy flagship Masdar, are 50:50 joint venture partners in the nation’s first commercial scale wind farm project. Total investment is estimated at $125 million.

According to the CEO, around five international companies are in contention for an Engineering-Procurement-Construction (EPC) contract to implement the 50 megawatt (MW) project at Thamrait in Dhofar Governorate.

Commenting on the current status of the project, Al Maghderi said: “Development of the wind farm project is progressing well. Design work has been completed in line with project implementation schedules. We expect to be in a better position (to make an announcement) in the second quarter of this year. The project is targeted for completion by around the first quarter of 2018.”

Selection of a competent bidder, according to the official, is a meticulous task given the highly specialised nature of wind farm development.

“There are a limited number of international players in this field. And as we are putting the accent on quality, we will be going in for a company that is prestigious and has extensive international experience in the execution of wind farm projects.”

Around 16,000 homes will receive their energy needs from this ambitious initiative when it comes into operation in 2017. Austrian-based international firm ILF Consulting Engineers is providing consulting and engineering services in the establishment of the venture.

Also making headway is RAECO’s trendsetting renewable energy pilot programme, the CEO said.

“The results of the photovoltaic (PV) project in Mazyounah are very encouraging, and plans are afoot for commercial-scale 3MW and 5MW systems in different locations within RAECO’s jurisdiction. The tendering and construction of these projects will be announced shortly. Potential locations include Masirah Island, wilayat Mahout, and event Musandam Governorate,” he added.




Turkmenistan to Begin Laying Linear Section of TAPI Gas PipeL

Preparation for the construction of the linear part of the Turkmen section of Turkmenistan-Afghanistan-Pakistan-India (TAPI) is being completed, Turkmen Ministry of Oil and Gas said in a statement Wednesday.

According to the statement, state owned Turkmennebitgazgurlyshyk prepared more than 6,312 meters of pipes of 1,420 mm diameter for welding up pipe sections. After laying the linear part of the pipeline in the Turkmen section, automation and remote control will be introduced which will enable control of the entire gas pipeline network from a single point.

Designers have finished survey work on the route from Galkynysh field till the border with Afghanistan. This will help choose the best route for the pipeline and to determine the characteristics of the pipe used for the transportation of gas, the Ministry said. Also, work continues on the analysis and sampling of equipment required for installation and use on the linear part of the pipeline and its supporting ground stations. Recently, the four TAPI nations signed initial investment agreement regarding the multi-billion dollar gas pipeline project. The much delayed TAPI gas pipeline project was formally inaugurated on December 13. TurkmenGaz will be the leader of the consortium and shall take 85 percent equity. Along with GAIL India, ISGS of Pakistan and Afghan Gas Enterprise (AGE) will also take 5 percent stake each. The TAPI pipeline will have a capacity to carry 90 million standard cubic metres a day (mmscmd or 3.0 BCFD) gas for 30 years and is planned to become operational in 2018.




Vietnam: Rosneft commences exploratory drilling offshore Source: Rosneft

Rosneft has started drilling exploration well PLDD-1X at Block 06.1 located offshore Vietnam. For the first time Rosneft is operating a drilling project, in International waters confirming the Company's competence and ability to implement technically complex drilling programs offshore.

The design depth of the well will be around 1380 m, while the sea depth in the area is about 162 m. The expected recoverable reserves of natural gas in the PLDD geological structure are estimated at 12.6 bcm, and 0.6 mt of gas condensate which can be developed by subsea completion and tied-back to the existing Lan Tay platform operated by Rosneft in Block 6.1.

The drilling will be performed using the HAKURYU-5 drilling rig owned and operated by Japan Drilling Co (JDC). Rosneft announced the signing of agreement with JDC at the Eastern Economic Forum-2015.

Following PLDD the Company will drill another exploration well in Block 05.3/11 also in the Nam Con Son basin. Incorporating the two wells into the same program will ensure synergy between the two projects and help reduce the timelines for implementation of the works, thus maximizing the efficiency of exploration projects at the Company’s Vietnamese assets.

Rosneft Vietnam also plans to shoot broadband 3D seismic of its existing Block 6.1 operatorship later this year to enhance ongoing production recovery and explore potential in deeper prospects.




Commenting on the drilling start, Rosneft Chairman of the Management Board Igor Sechin said:

'Rosneft team has already demonstrated their competence in Russia during the successful drilling of the world's northernmost well in the Kara Sea, which resulted in the discovery of a new deposit, the Pobeda field.

Today, the Company starts a similar project as a drilling operator in international waters. I am sure that the experience gained in Vietnam will be used by the Company not only in its activity in the southern seas; these competences will find application in planning and implementation of upstream projects in remote areas.

I would especially like to emphasize that this project is an example of advanced cooperation with the Company's partners in the Asia-Pacific: Petrovietnam and ONGC. We appreciate not only the current

progress of joint projects implementation in Vietnam, but also the future prospects for their development.'

Background

Rosneft is currently involved in projects of gas and condensate production and exploration in two blocks offshore Vietnam:

• Block 06.1: Rosneft Vietnam B.V. owns 35% of the project and is the project operator; The project is based on the Production Sharing Contract (PSC). The PSC area comprises two gas condensate fields – Lan Tay and Lan Do. The deposits are located 370 km off the coast in the Nam Con Son basin with a sea depth of up to 190 m. The field's initial gas reserves are about 68 billion cubic meters. By June 2015, the block produced its 300-millionth barrel of oil equivalent (or more than 46 billion cubic meters of gas).

• Block 05.3/11: Rosneft Vietnam B.V. owns 100% of the project and is the project operator. The license area is located in the region with proven oil and gas content and infrastructure, and is adjacent to fields under development in Block 06.1. The resources of block 05.3/11 are currently estimated at about 40 billion cubic meters of gas and 9 million tons of gas condensate.

Rosneft using JDC's rig to drill offshore Vietnam




Senegal: Cairn Energy announces second successful appraisal well Source: Cairn Energy Cairn Energy has announced the successful testing of the SNE-3 appraisal well offshore Senegal. Operations have been safely and successfully completed following drilling, coring, logging and drill-stem testing (DST). The well is now being plugged and abandoned. Cairn’s analysis of the extensive dataset collected is continuing with initial results as follows:

• Two drill stem tests were conducted within the Upper Reservoirs, confirming the deliverability of these units;

o DST 1a flowed at a maximum rate of ~5,400 barrels of oil per day (bopd) and a main flow rate of ~4,000 bopd over a 24 hour period from a 15 metre (m) zone

o For DST 1b an additional zone of 5.5m was added and a combined maximum rate of ~5,200 bopd measured, with an associated main flow rate of ~4,500 bopd over a six hour period

o Both main flow periods utilised a 56/64” choke

• Multiple samples of oil and gas recovered to surface from wireline logs and drill stem tests

• Confirmation of similar reservoir quality and correlation of the principal reservoir units between SNE-1, SNE-2 and SNE-3

• 144m of continuous core taken across the entire reservoir interval with 100% recovery

• Similar oil-down-to and oil-up-to depths seen in SNE-1 and SNE-2 – 101m gross (95m in SNE-1 and 103m in SNE-2)

• Initial indications confirm the same 32 degree API oil quality as seen in SNE-1 and SNE-2

Resource estimates for the SNE field continue to be revised and an update will be announced at the company’s preliminary results on 15 March 2016.




Malaysia Petronas denies wall away from Canadian PNW LNG

Contrary to recent media reports that Petronas is looking to ditch the $11.4 billion Pacific North West LNG project, the Malaysian giant said Wednesday it is moving towards the financial investment decision.

National Post, a Canadian newspaper said earlier this week that Petronas has been put off by the newly proposed climate-change priorities revealed by the new prime minister Justin Trudeau, allegedly threatening to walk away from the project.

However, in its response to the reports, Petronas said it is awaiting the completion of the Canadian environmental impact assessment process for the PNW LNG project, which is still ongoing. The company will then review the report “to further determine their impact on the overall cost structure and schedule of the project.”

Based on the outcome, combined with LNG market outlook and overall project commerciality, Petronas said it will develop the proposal for the final investment decision on the project.

Through its unit Pacific NorthWest LNG, Petronas is proposing to develop a natural gas liquefaction and export facility on Lelu Island in the District of Port Edward, British Columbia.

The proposed facility will comprise an initial development of two LNG trains of approximately 6 million tons per annum each, and a subsequent development of a third train of approximately 6 mtpa.

Petronas, Sinopec, JAPEX, Indian Oil Corporation and Petroleum BRUNEI are all shareholders in Pacific NorthWest LNG and the associated natural gas supply.




U.S. oil production continues to decline below its year-ago level Source: U.S. Energy Information Administration, Petroleum Supply Monthly

U.S. monthly crude oil production in December 2015 continued to decline, as oil production reached its lowest level since November 2014. Production also declined from year-ago levels for the first time in more than four years. This continued production decline is the result of lower crude prices, which have declined more than 70% since the summer of 2014.

Crude oil production in December 2015 averaged 9.3 million barrels per day (b/d), down 166,000 b/d from December 2014 and the first year-over-year decline in U.S. monthly oil output since September 2011, according to the latest data from EIA's Petroleum Supply Monthly report released at the end of February.

Domestic oil production has generally declined month to month since reaching a 44-year peak of almost 9.7 million b/d in April 2015. Even as production declined, output was still above levels from the same month a year earlier until EIA published production for December 2015.

Most of the decline in oil production has occurred in states where a large portion of output comes from tight oil formations, including North Dakota, Texas, and New Mexico. Oil production from tight formations accounted for most of the increase in U.S. oil production during the past five years, and it is now making up most of the decline in output.




NewBase 10 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 dip as global oversupply outweighs strong demand Reuters + NewBase

Oil prices dipped early on Thursday after U.S. crude hit 2016 highs the day before and Brent shot back over $40 per barrel, with analysts warning that larger gains would be unwarranted as a global glut continues to outweigh strong demand.

International Brent crude futures were at $40.95 per barrel at 0142 GMT, down 12 cents from their last close. U.S. West Texas Intermediate (WTI) crude futures were down 5 cents at $38.24 per barrel.

The dips came after prices rose as much as 5 percent on Wednesday, with U.S. crude hitting three-month highs following a big gasoline inventory drawdown, which overshadowed record-high crude stockpiles.

But analysts warned that a global crude production overhang of over 1 million barrels per day (bpd) showed few signs of abating.

With U.S. crude inventories at records despite strong demand, the focus lies on a potential agreement between producers from theOrganization of the Petroleum Exporting Countries (OPEC), led by Saudi Arabia, and non-OPEC exporters led by Russia to rein in output.

Yet beyond announcing talks about freezing output near record levels, no agreement has been reached. Barclays said there was no talk of a production cut during a research trip to Saudi

Oil price special

coverage




Arabia and that the country's goal was to maximize its oil revenue by maintaining current production levels.

Barclays said that Saudi Arabia would likely keep production around 10.2 million bpd over the next five years. Most analysts expect the oil glut to last into 2017 or even 2018, resulting in relatively low crude prices.

Only by 2020 is there a consensus for prices to rise towards $70 a barrel, based on lower production due to low investment and defaults as well as strong fuel demand especially from China and other emerging markets.

But Deutsche Bank said that China might see lower than expected fuel demand growth from the 2020s.

"Chinese oil demand growth, the largest single contributor to world oil demand growth, may begin to flatten more quickly than some long-term projections indicate," the bank said in a report to clients this week.

"This could result in world oil demand growth falling from its 2000-2016 trend of 1.1 million bpd year-on-year to only 800,000 bpd ... by 2024."

A slowdown in China's oil demand would have significant impact on global crude prices as it has accounted for 37.5 percent of world oil demand growth since 2010, Deutsche said.




NewBase Special Coverage

News Agencies News Release 10 March 2016

China’s Oil Demand Could Be 19% Below IEA Forecast, Warns Merrill Baron Asia - By Shuli Ren

Is it time to sell into the rally?

Brent crude has recovered from its late January low of $27.88 to trade at $40.95 this morning.

China’s new five-year plan (for 2016-2020), unveiled last weekend, sets a meaningfully negative tone for China’s oil demand. If fully implemented, China’s oil demand could be 19% below the latest IEA forecast, estimates Bank of America Merrill Lynch.

Choking in foul air, Beijing wants to boost the electric vehicle industry and reduce the number of gasoline cars on the street. China now plans to increase the number of electric vehicles to 5 million units by 2020, or 5.9% of total sales volume (versus nearly zero in 2014). This drive could replace 23% of China’s total transport fuel demand, and China’s oil demand could be 16% below the IEA forecast. Merrill has the numbers:




International Energy Agency (IEA) forecasts China’s oil demand to grow to 13.6 mb/d by 2021 from 11.2 mb/d in 2015, implying 2.4 mb/d growth. The incremental oil demand growth from China would account for 33% of the projected total global oil demand growth of 7.2mb/d during the same period.

NEV growth, if fully implemented, may trigger oil demand replacement by 0.4 mb/d, which would erode 16.3% of IEA’s estimated China oil demand growth of 2.4 mb/d.

Modelling after U.S.’s strategic reserve system, China had planned to build emergency oil storage reserve of 450-500 million barrels. But Beijing is now delaying this resolve:

The 13th FYP is to delay the completion of phase II (Storage capacity 170mn bbls) for about two years from 2015; Phase III program (232mn bbls) seems quite uncertain now, according to ICIS China. Emergency stock build has driven China’s headline oil demand well above the underlying consumption in the past years. Reflecting the changes in China emergency reserve plan, China’s oil demand would be 3.2% below the IEA forecasts in 2016-20.

As we head into the earnings season for China’s oil majors, Merrill is decidedly negative towards upstream pure play CNOOC (883.Hong Kong/CEO) and its oil services partner China Oilfield Services .

CNOOC has already rallied 12% this year and its current stock price implies oil price of $64-65 per barrel. Brent crude was trading at $40.88 this morning. And since China Oilfield Services court CNOOC as a major customer, “based on our US$46/61/bbl average Brent forecast for 2016/17E, the 33% YoY increase in oil won’t lead to the same magnitude of oil companies’ capex increase, we believe, as the elasticity of capex increase to oil price below $60/bbl is basically negligible,” wrote analyst Sonia Song and team.

China’s oil majors gained today. China Oilfield jumped 3.1%, CNOOC rose 2.1%, Kunlun Energy gained 2.9%, PetroChina (857.Hong Kong/PTR) rose 1.7%, Sinopec (386.Hong Kong/SNP) was up 1.5%. Overnight, the United States Oil Fund (USO) soared 5.2%, theEnergy Select Sector SPDR Fund (XLE) gained 1.6%.




Russia's Dilemma: Squeeze Oil Industry Without Strangling Growth

While the world focuses on Russia’s oil-freeze talks with OPEC, there are discussions behind closed doors in the Kremlin that will have a much more significant impact on the nation’s energy industry.

The petrodollars that underpin Russia’s national budget are evaporating. When crude prices were high, increasing revenue simply meant encouraging companies like Rosneft OJSC and Lukoil PJSC to push output higher, said Alexander Nazarov, an oil and gas analyst at Gazprombank. Now the Kremlin and the companies must figure out a new way to divide up the bounty, even measures that could harm output in the long term, he said.

“The Russian budget is starving,” Nazarov said by e-mail. “The government understands that with a tax hike it would hurt future prospects, but it has no choice.”

While President Vladimir Putin has reasserted control of oil and gas production, much of the industry remains independent -- managed through a delicate balancing act that maximized tax revenue while supporting growth. For a decade the strategy succeeded as output grew to a post-Soviet record while supplying about half budget revenue. The collapse in crude prices destroyed the equilibrium, leaving Russia facing a deficit and a second year of recession.

In response to the slump, Russian producers are already curbing the investment needed to keep the oil and gas flowing, a process that could accelerate if the Kremlin raises taxes. Nevertheless, their profits are a tempting source of extra revenue, particularly as the weaker ruble has offset the impact of the decline in dollar-denominated crude prices.

Rosneft, the nation’s biggest producer, will report adjusted net income of 487 billion rubles ($6.6 billion) for 2015, according to a Bloomberg survey of 17 analysts, a 40 percent increase from the previous year. Lukoil, which reports in dollars, is projected to post a 9.5 percent decline in earnings to $4.27 billion for 2015. In the Russian currency, the company’s adjusted profit is estimated to have risen 72 percent to 313 billion rubles.

Royal Dutch Shell Plc, Europe’s largest oil company, reported a 53 percent drop in dollar-denominated adjusted net income last year.

Traditionally the Kremlin has carefully managed the tax regime for oil producers, assigning higher rates to the bulk of low-cost fields dating from the Soviet era while taking less from costlier new projects including offshore or heavy crude. Even for lower-cost producers the government

has eased rates over the years.

Higher Taxes




It diverted from this gradual decrease in the tax burden last year, implementing new rules for 2016 that are expected to collect 200 billion rubles more than previously planned from the industry, Economy Minister Alexei Ulyukayev said last year. The state also approved two increases in sales tax on fuels such as gasoline and diesel, only part of which the companies may be able to pass along to customers at the pump.

A proposal from the Finance Ministry to increase the tax burden again could cost the industry about $11 billion of earnings in 2017, according to VTB Capital. The state “might take as much as it wants, this depends on the general situation in the economy,” said Dmitry Loukashov, an analyst at the bank.

The government has made no final decision on whether to implement the proposals, Deputy Prime Minister Arkady Dvorkovich said last month.

Reduced Investment

Oil producers asked to be left alone in a Jan. 27 meeting with the Energy Ministry, according to Bashneft Chief Executive Alexander Korsik. The government may be receptive to that argument.

The Kremlin has been very clear that raising taxes isn’t an attractive option and they will only do it if they cannot balance the budget otherwise, said Ivan Mazalov, who helps to manage $2 billion at Prosperity Capital Management Ltd. The government is still able to cut spending, borrow, raise money from privatization and ask for higher dividends from state-controlled companies, he said.

Producers are already responding to the price slump in a way that could affect output. Lukoil’s billionaire Chief Executive Officer Vagit Alekperov curbed spending last year to about $9 billion, about $1.5 billion less than 2014, and plans keep it around that level until 2017. Rosneft’s capital spending fell in dollar terms in 2015 compared with 2014. The weaker ruble means the company will actually increase spending in the local currency by about a third this year and next year, compared with 2015.

The Energy Ministry expects the industry’s seven-year expansion to end this year, with output stable near 2015 levels. In the ministry’s worst-case scenario, where prices are still about $40 a barrel by 2020, production may slump 14 percent in the next five to 10 years. Tough Market An expected increase in oil prices in the second half could also help ease the pressure on the nation’s budget, according to HSBC Holdings Plc, which raised its recommendation on Rosneft to hold last month. Brent crude recovered to above $40 a barrel for the first time since December this week, compared with a low of about $27 in January, after major producers including Saudi Arabia and Russia reached a tentative agreement to freeze output.

Prices may go lower if oversupply and weak economic growth persist, according to Edward Chow, a senior fellow at the Center for Strategic and International Studies in Washington. The historical average price of oil over the last 155 years is in the mid-30s in today’s dollars, while the Russian budget is based on $50 oil, he said.




“If I were a Russian oil producer, particularly if I am not majority owned or favored by the government, I would be worried about the government take going up in the next couple of years,” Chow said.

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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 10 March 2016 K. Al Awadi




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New base 805 special 10 march 2016