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    Trudeau is set on Saving Oil Pipeline (Friday, 20 April 2018)

    20 Apr 2018, 11:00 pm

    Canadian Prime Minister Justin Trudeau and Alberta Premier Rachel Notley have signaled they could put money behind Kinder Morgan’s Trans Mountain pipeline expansion as they vow to make sure it gets built.

    Here are ways they could do it as the company threatens to abandon the C$7.4 billion ($5.9 billion) project amid steadfast opposition in British Columbia, the province that the line crosses to take crude from Alberta’s oil sands to the Pacific Coast.

    Buying a piece of the project. Notley said her province would be willing to invest directly in the project, while Finance Minister Bill Morneau has hinted that a stake purchase by the federal government wasn’t ruled out.


    After failing to convince British Columbia Premier John Horgan to end his legal battle against Trans Mountain, Trudeau said Sunday that he asked Morneau to begin a “formal financial discussion” with the company.

    While buying a stake seems more like a last resort than the first option, it has raised the question of how much of taxpayers’ money that would cost. It would depend on how big a stake.

    How much is Trans Mountain worth? The expansion is valued at roughly C$1.2 billion, according to Bloomberg calculations based on a share price of about C$17.50 for Kinder’s Canadian unit, analyst valuations for the existing business at around C$14, and 345 million shares Kinder has spent C$1.1 billion so far on the project, according to a research note from RBC Dominion Securities Inc. analysts Robert Kwan and Tim Tong Kinder Morgan Canada was created in an initial public offering in May 2017 that valued the business at about C$5.8 billion. Its market capitalization is about C$6.5 billion.

    “Any framework would allow Kinder Morgan Canada to retain the majority of economic upside while mitigating cost overruns related to delays,” Bank of Nova Scotia analysts Robert Hope and Arnav Gupta wrote in a research note Monday. “We do not expect a majority purchase of the pipeline is a likely scenario.”

    If Kinder seeks to get a return on the money already sunk into the project, a buyout could be expensive, said Paul Bloom, president of Bloom Investment Counsel Inc. in Toronto, which owns about 300,000 shares of Kinder Morgan Canada. “Maybe I would like the project to be bought out,” he said in reference to how Kinder is potentially looking at it. “But only if it’s for a stupid price.”

    Kinder Morgan said Sunday it won’t make further comments “until we’ve reached a sufficiently definitive agreement on or before May 31.”

    Taking on extra construction costs. Canada could use legal powers to ensure the project is built and guarantee payment for extra costs, according to Michael Kay, a Bloomberg Intelligence senior energy analyst. British Columbia’s Horgan said after meeting Trudeau on Sunday that he will press ahead with legal challenges.

    “Assurance that they won’t incur the extra costs of delays would probably be one place to start,” Kay said. “Kinder Morgan would take direct cash anytime, but I don’t know if that’s the direction we are going to go.”

    Offering loan guarantees. Canada has offered loan guarantees on big projects such as the Maritime Link and Muskrat Falls electricity projects on the country’s east coast. Offering something similar to Kinder could lower the company’s borrowing costs, allowing the government to help without giving direct cash, said Fred Lazar, an economics professor who studies industrial policy at York University in Toronto. Whether the government buys a stake or offers other guarantees “is going to be a function of what’s less costly,” he said.

    Bottom line. Trudeau has already taken a major stand by calling Trans Mountain vital, and about the only option he hesitated to speak about was nationalization. Past governments have aided the Hibernia oil project off Newfoundland and Labrador, aircraft maker Bombardier Inc., automakers and the forest industry.

    “We are absolutely focused on making sure we make this construction season,” Trudeau said, adding Canada loses out on C$15 billion worth on revenues a year from selling Alberta’s landlocked crude at a discount because of transportation bottlenecks.

    “I don’t think a stake in the project is where they are going to go, but crazier things have happened,” said Kay at Bloomberg Intelligence.


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    Viability of French-Spain Gas Pipeline Questioned (Friday, 20 April 2018)

    20 Apr 2018, 8:00 pm

    A report prepared for the European Commission has questioned the economic viability of plans to build a huge gas pipeline between Spain and France designed to boost security of supply in Europe, five sources told Reuters.

    The Commission has long backed the 3 billion euro ($3.7 billion) Midi-Catalonia (Midcat) pipeline that would more than double the amount of gas that can be piped across the Pyrenees mountains that border the two nations.

    French gas grid Terega, owned by Italy’s Snam, and Spain’s Enagas want to invest in the project, which has strong support from European Union Climate Commissioner Miguel Arias Canete, a Spanish national.

    But the project has faced opposition from French energy regulator CRE, who says Midcat would push up consumer prices without improving security. French gas network firm Engie-owned GRTgaz also questions the need for the pipeline.

    Now a study by Poyry, a consultancy appointed to assess the first phase of Midcat for the Commission, indicates the project is unlikely to be economically viable.

    It said it would only achieve “financially viability ... in scenarios with a tight LNG market”.

    The study says the 120-km (75-mile) STEP pipeline across the Pyrenees - the first and central part of the broader Midcat project - would only be viable if LNG prices over a long period remained significantly higher than pipeline gas prices. Specialists say that is unlikely.

    The report, seen by Reuters, will be the basis for a Commission discussion on Wednesday of priority EU infrastructure plans termed Projects of Common Interest (PCI).

    The Commission has declined requests to release the report, citing commercial confidentiality, and did not respond to a request for comment. Poyry declined to comment.

    Terega infrastructure director Michel Boche said the STEP pipeline would cost 442 million euros of which 290 million for Terega and 152 million for Enagas.

    The firms have sent an investment proposal to the CRE. In October they will present the case to the European Union, which could provide subsidies of up to 50 percent.

    Regulated network operators typically earn around a 5.5 percent return on their asset base on such projects.


    Boche said the expected flow would be mainly from France to Spain but the interconnector would be reversible in case of need. Last winter, gas flowed from Spain to France only about two days, to boost Britain’s gas supplies during a cold spell.

    Many experts question the need for another interconnector, saying that existing cross-Pyrenees pipelines are already underutilized, even during periods of high demand.

    “If there were a real demand for Midcat, the market would already have built those interconnectors,” said one of the sources familiar with the Poyry report.

    The project has attracted critics.

    “The Midcat project is not coherent with the EU’s climate commitments and its promises to reduce reliance on fossil energy,” said Michele Rivasi, a French member of the European Parliament.

    Friends of the Earth Europe’s Antoine Simon said STEP was designed as a precursor to a bigger 3 billion euro investment in the Midcat pipeline across France and the Iberian peninsula.

    “STEP is a reasonable project that responds to the desire of the heads of state of France, Spain and Portugal to strengthen our gas interconnections and boost security of supply in Europe,” Terega’s Boche said.

    Spanish European MP Xabier Benito Ziluaga said Midcat made no economic sense and that Madrid backed the plan to support its gas industry. “It is a project based on private interests, not on public interest or objective evidence,” he said.


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    France's Energy Major is Getting Ready for an Electric Future (Friday, 20 April 2018)

    20 Apr 2018, 6:00 pm

    Total SA deepened its foray into power and gas retail, underlining a strategy shift among European oil majors as the global transition to cleaner energy gathers pace.

    The French company agreed to buy Paris-based utility Direct Energie, adding 2.6 million electricity and gas customers at home and in Belgium. The deal puts Total in a stronger position to lure households away from market leaders Electricite de France and Engie, and follows a similar utility acquisition by Royal Dutch Shell in December.

    The large company’s move into the European power market shows the majors are preparing for a future in which fossil fuels are diminished in the energy mix and consumers demand charging points alongside gasoline pumps at fueling stations. For Total, it’s also part of a plan to add customers for its growing natural-gas production and to increase control of its distribution.


    “We now have, among the European oil majors, an unexpected battle emerging for market share in western European gas and power,” said Rob West, an analyst at Redburn Europe, “It is fascinating.”

    Total will buy 74.3% of Direct Energie from Impala SAS and other investors for 42 euros a share, it said Wednesday. Following the 1.4 billion-euro ($1.7 billion) transaction, Total will offer to buy out minorities at the same cost per share, a 24% premium to the three-month average stock price. The deal values Direct Energie at about 12.5 times projected 2018 earnings, Total said.

    “The push to grow along the electricity value chain is in line with Total’s stated strategy, although we did not expect something this significant so soon,” said Biraj Borkhataria, an analyst at RBC Capital Markets. “It remains unclear what synergies the two portfolios could generate, but the headline acquisition multiple looks high versus utility peers.”

    The deal, unanimously approved by Direct Energie’s board, is not Total’s first acquisition in the utilities business. It bought Belgian power retailer Lampiris in 2016, as well as French battery maker Saft Groupe, gaining storage systems for generators. Last year, Total agreed to buy liquefied natural gas assets from Engie, and took a minority stake in France’s Eren Renewable Energy.

    Anglo-Dutch competitor Shell has also ventured into electricity supply, snapping up the UK’s First Utility Ltd. in December, while Italian oil giant Eni has entered France’s gas and power retail market. Norway’s Statoil has expanded in offshore wind in recent years.

    Total, which already has 1.5 million gas and power clients, aims to have more than 6 million in France and 1 million in Belgium by 2022. It’s also targeting capacity of 10 gigawatts of gas-fired power plants and renewable electricity generation within five years.


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    Osbit Secures DeepOcean Plough Upgrade to Support Nord Stream 2 Pipeline (Friday, 20 April 2018)

    20 Apr 2018, 2:00 pm

    Osbit Ltd, the offshore engineering and technology company, has secured a project with DeepOcean to deliver a significant upgrade to a subsea plough, enhancing its capabilities for the installation of a new gas pipeline.

    DeepOcean’s Advanced Multi-Pass Plough (AMP500) will be deployed to the Baltic Sea for the construction of the 1,200km Nord Stream 2 Pipeline, which will transport natural gas from Russia to the European Union.

    To meet the requirements of the Nord Stream 2 project, the AMP500 is required to accommodate a larger diameter pipeline.


    Osbit, through a competitive tender process, has been awarded the upgrade, which will transform the asset into a state-of-the-art subsea vehicle that can support the trenching and laying of the 1.5-meter diameter pipeline.

    This will be facilitated by implementation of a new share, major pipe handling equipment upgrades and the installation of Osbit’s control system which will provide the latest operational control technology for the plough.

    The modular nature of the control system enables it to be transferred onto other trenching assets within the DeepOcean fleet, which reduces duplication of inventory. This is the second control system Osbit has supplied for DeepOcean, after it installed the technology as part of an upgrade of the T1 Trencher, in 2017.

    The project will be delivered at Port of Blyth, where both companies have quayside operations, and will be completed to the required strict timescale of 30 weeks.

    Robbie Blakeman, Director at Osbit, said: “Our unique structure, systems and processes ensure we can deliver this plough upgrade quickly and meet the timescale required by DeepOcean and the Nord Stream 2 development, without compromising safety, quality or reliability.

    “Being located close together at Port of Blyth enhances the collaborative nature of this project as we work closely with DeepOcean to deliver our solution, which will enable the AMP500 to effectively operate in the Baltic Sea and other locations requiring large product installation.”

    Pierre Boyde, Managing Director of DeepOcean’s Cable Lay and Trenching Operation, said: “This is a great example of two technology-led companies from within the North East England supply chain coming together to employ innovative solutions to address a customer requirement. This project will build upon our existing relationship with Osbit and is part of DeepOcean’s commitment to maintaining and developing the most advanced fleet of cable lay and trenching assets in the industry.”


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    Eni Has No Plans to Pull Out of Rosneft Deal after Sanctions (Friday, 20 April 2018)

    20 Apr 2018, 10:00 am

    Italian oil major Eni has no plans to pull out of its joint venture with Russia’s Rosneft despite escalating sanctions against Russia, the head of Eni said on Wednesday.

    “We certainly have not pulled out, we’re working with them,” CEO Claudio Descalzi said on the sidelines of a conference.

    Eni, one of Europe’s biggest importers of Russian gas, extended a cooperation agreement with Rosneft last year to explore the Russian Barents Sea and the Black Sea, and to consider further opportunities together.


    But after the United States imposed major new sanctions against Russia earlier this month, speculation has been growing that companies working with Rosneft might have to reconsider deals.

    “We need to see why more sanctions have been imposed and how they will be applied, but it’s not that we’ve closed relations with Rosneft, we are here and will remain here,” Descalzi said.

    In March Exxon Mobil Corp said it would exit some joint ventures with Rosneft, citing Western sanctions first imposed in 2014.

    Last month, a source close to the operations said Rosneft and Eni had failed to make a commercial oil discovery in the Black Sea as the well they were drilling turned out to be dry.

    Descalzi, who acknowledged Eni and Rosneft had not found much in the Black Sea well, said the two companies were now looking further north and would be moving to drill wells in the Russian Barents Sea.

    Eni buys almost 21 billion cubic metres of gas per year from Russia covering 29 percent of gas supplies to Italy.

    “It’s strategic for the energy security of Italy,” Descalzi said.


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    OPEC's New Price Hawk Saudi Arabia Seeks Oil as High as $100 (Friday, 20 April 2018)

    20 Apr 2018, 8:00 am

    Top oil exporter Saudi Arabia would be happy to see crude rise to $80 or even $100 a barrel, three industry sources said, a sign Riyadh will seek no changes to an OPEC supply-cutting deal even though the agreement’s original target is within sight.

    The Organization of the Petroleum Exporting Countries, Russia and several other producers began to reduce supply in January 2017 in an attempt to erase a glut. They have extended the pact until December 2018 and meet in June to review policy.

    OPEC is closing in on the original target of the pact - reducing industrialized nations’ oil inventories to their five-year average. There is no indication yet, however, that Saudi Arabia or its allies want to wind down the supply cut.


    Over the past year, Saudi Arabia has emerged as OPEC’s leading supporter of measures to boost prices, a change from its more moderate stance in earlier years. Iran, once a keen OPEC price hawk, now wants lower prices than Saudi Arabia.

    Industry sources have linked this shift in Saudi Arabia’s stance to its desire to support the valuation of state oil company Aramco ahead of the kingdom’s planned sale of a minority stake in an initial public offering.

    The supply cut has helped boost oil prices this year to $73 a barrel, the highest since November 2014. Oil began a slide from above $100 - a price that Saudi Arabia endorsed in 2012 - in mid-2014, when growing supply from rival sources such as U.S. shale began to swamp the market.

    But the kingdom wants the rally to go further. Two industry sources said a desired crude price of $80 or even $100 was circulated by senior Saudi officials in closed-door briefings in recent weeks.

    “We have come full circle,” a separate high-level industry source said of the change in Saudi thinking. “I would not be surprised if Saudi Arabia wanted oil at $100 until this IPO is out of the way.”

    Once the Aramco share sale is done, Riyadh would still want higher prices to help fund initiatives such as Vision 2030, an economic reform plan championed by Crown Prince Mohammed bin Salman.

    “Saudi Arabia wants higher oil prices and yes, probably for the IPO, but it isn’t just that,” an OPEC source said.

    “Look at the economic reforms and projects they want to do, and the war in Yemen. How are they going to pay for all that? They need higher prices.”

    To be sure, OPEC and Saudi Arabia have no official price target and say the objective of the production cut is to balance supply and demand, and reduce the inventory glut.

    But guidance on preferred price levels comes from officials speaking off the record, and from industry sources who have discussed the issue with Saudi officials.

    “I personally think that now $70 is the floor for oil prices,” a second OPEC source said. “But OPEC is unlikely to make any changes in June, maybe by the end of the year. The market still needs support.”


    OPEC and its partners meet on June 22 to review policy and before then a ministerial monitoring panel gathers in Jeddah, Saudi Arabia, on April 20.

    By OPEC’s parameters, the deal has worked. Oil stocks in developed economies in February stood a mere 43 million barrels above the latest five-year average, down from 340 million barrels above in January 2017.

    The cuts have been even bigger than those specified in the deal, thanks in part to a slide in Venezuelan production due to an economic crisis in the South American country.

    Compliance has reached 150 percent, according to OPEC, meaning the organization’s members have cut production by about 1.8 million barrels per day, 600,000 bpd more than pledged.

    Few OPEC sources call for an exit strategy. Most officials are talking of introducing additional inventory metrics to assess the success of the deal, and of a need to support investment in new production to avert any supply crunch.

    The impression is that oil prices are seen as not yet high enough to encourage sufficient oil investment.

    “We will know what will be the good price when the market is balanced and we have enough investments,” the United Arab Emirates’ energy minister, Suhail al-Mazroui, told Reuters last week. “We need to have more investments coming.”

    The Jeddah meeting of the Joint Ministerial Monitoring Committee is unlikely to change the parameters for assessing the deal’s success, Mazroui and other OPEC officials said, and sources see little chance of a major tweak in June.

    “Even if we reach the five-year average before June, it does not mean we just go and open the taps,” a third OPEC source said. “We have to test it.”


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    Addax Petroleum Workers Begin Strike Action (Friday, 20 April 2018)

    20 Apr 2018, 6:00 am

    Workers of Addax Petroleum Development Nigeria Limited, a subsidiary of Addax Petroleum, have announced the commencement of an indefinite strike action against the Management of the company.

    The workers’ action was sequel to the expiration of the ultimatum the company’s chapter of PENGASSAN gave the management led by Mr. Klappa over “some unresolved burning issues.”


    The strike action involves the 166 members of the Petroleum and Natural Gas Senior Staff Association of Nigeria (PENGASSAN) staff from the company and 98 others who are management staff.

    This industrial action may threaten the country’s oil output as the company currently produces 30,000 barrels daily of oil from its offshore and onshore locations in Lagos, Port Harcourt, Asaba, Warri, and Izombe in the Niger Delta. The country currently produces approximately 2.25 million per barrel daily.

    Chris Ogiewonyi, chairman PENGASSAN at Addax said the indefinite action was a culmination of a series of failed and inconclusive communications between the workers’ union and the management over alleged “culture of impunity against some of its officials.

    He listed some of the issues to include:

    • Alleged unilateral interpretation of the subsisting collective bargaining agreement (CBA) reached between the union and management in August 2014 on issues bordering on activation of non-statutory remunerations to members.
    • Alleged selective, targeted victimization of union leaders identified as not working in line with management interest.
    • The stagnation of some staff for between 10 to 12 years, and discriminatory promotion of workers.

    Addax Petroleum was originally part of the Addax and Oryx Group of Companies (AOG) which were established in 1987, but the company became an independent entity in 1994.

    In August 2009, it was bought over by Sinopec, the world’s biggest oil refiner. Addax was initially focused on the oil and gas in the Middle East, the North Sea, and Africa, but has recently focused its effort on West Africa. In 2017, the company’s former chief executive was arrested and tried for corrupt practices he allegedly carried out while working in Nigeria.


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    Eni Approves Development Plan for Merakes Discovery, Offshore Indonesia (Friday, 20 April 2018)

    20 Apr 2018, 3:00 am

    Eni announces the approval of a development plan for the Merakes field, offshore East Kalimantan, Indonesia. The energy minister granted approval just three months after the submission of the plan and less than 11 months after Eni started production from its deepwater Jangkrik asset in Muara Bakau, Indonesia.

    The Merakes field is estimated to hold about 2 Tcf of natural gas, is in 1,500 m water depth, 35 km southwest of the Jangkrik floating production unit (FPU). The field was discovered by the Merakes 1 well in 2014 which encountered lean gas in high-quality reservoir sands of Pliocene age. In January 2017, Eni successfully drilled and tested the Merakes 2 appraisal well, recording excellent gas deliverability.


    The proximity of Merakes discovery to the Jangkrik FPU will allow Eni to maximize synergies with existing nearby infrastructures as well as reduce costs and start-up time of this second deepwater development in Indonesia.

    The approved plan foresees the drilling and completion of six subsea wells and the construction and installation of subsea systems and pipelines which will be connected to the Jangkrik FPU. The gas will be shipped through the existing pipelines from the Jangkrik FPU to the Bontang LNG processing facility in East Kalimantan.

    Merakes production, combined with Jangkrik, will contribute to the life extension of the Bontang LNG facilities, which supplies LNG to domestic and export markets.

    The approval of the Merakes development plan is a fundamental step to progress towards the final investment decision of the project. Merakes is another outcome of the Eni “near field” exploration and appraisal strategy. “We are proud of Eni’s partnership with Indonesia, a key country in the company’s global strategies,” said Eni’s CEO, Claudio Descalzi.

    Eni is the operator of East Sepinggan PSC through its subsidiary Eni East Sepinggan Limited which holds 85% participating interest, while Pertamina Hulu Energy holds the remaining 15%.


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