Nigerian oil and gas company Optimum Petroleum, together with its partner Lekoil, is progressing towards appraisal and development program at the Ogo discovery located in OPL 310 block offshore Nigeria.

Lekoil said on Friday it had reached a resolution with Optimum Petroleum, its partner on and the operator of OPL 310, to progress appraisal and development program activities at the Ogo discovery, which sits within the Block. Optimum and Lekoil are initially targeting a two-well program over the next twelve to eighteen months.

However, this is subject to receiving an extension of the OPL 310 license from the Ministry of Petroleum Resources for the Block and the companies securing the necessary funding for the program.

Lekoil and Optimum have agreed to drill two additional appraisal-development wells, contingent on the results of the initial two-well appraisal campaign and the associated extended well tests to be undertaken. All wells will be designed to be compatible with an early production scheme.

Both Optimum and Lekoil have agreed to progress the appraisal of the Block and conversion to an Oil Mining License (OML), as soon as practicable. Assuming a successful appraisal, a full field development (FFD) program will be undertaken and embarked upon by Lekoil and Optimum with an industry partner, discussions on which are at an advanced stage.

Assuming granted, which is at the discretion of the Department of Petroleum Resources, the OPL to OML conversion is expected to extend the license by twenty years.

It is also worth reminding that there has been an ongoing dispute as to the legitimate ownership of a 22.86 percent stake in OPL 310. This dispute has been the principal reason that development of the Block has been delayed.

Rather than pursue this matter further, the companies have agreed to use the 22.86 percent equity stake in the Block as a potential funding and security vehicle for the accelerated development of the Block by an industry partner or a third party that elects to farm-in to the Block to fund field development. The potential funding partner may be sourced by either Lekoil or Optimum.

Although the agreement does not address the recovery of the $13 million consideration previously paid by Lekoil with respect to the acquisition of the shares of Afren Oil & Gas (Nigeria) Limited (AOGNL) in 2015 (which held the 22.86 percent participating interest in OPL310), Lekoil said it is working with Optimum on a resolution of this matter alongside the possible allocation of the 22.86 percent to a potential funding partner and remains hopeful that an agreement can be reached.

The agreement

Pursuant to the agreement, a payment structure for previously outstanding G&A arrears payable by Lekoil to Optimum in the amount of approximately $3 million has been agreed, with approximately $1 million having been paid to date, with the balance to be paid by mid-October 2019.

Lekoil will also pay Optimum $5 million for an operator’s fee in regard to Lekoil’s 17.14 percent participating interest upon receipt of the extension.

The agreement also makes provision for Lekoil to pay Optimum certain production prepayments from the proceeds of a continuous sale of crude oil produced from Ogo, such amounts being subject to 2P reserves or aggressive production milestones being achieved. The payments, once due, include a $10 million per year payment for five years following completion of a successful well (being a well capable of producing 5,000 BBL/d of Crude Oil).

Further, Lekoil has agreed to pay 42.85 percent of $10 million payable to the Nigerian Government on conversion of OPL 310 to an OML and 42.85 percent of $ 10 million to the Nigerian Government on reaching first oil. The balance of the two $10 million payments will be made by the potential funding partner.

Upon receipt of the extension, Lekoil will also pay the Ministry of Petroleum Resources the fee to be prescribed by the Minister of Petroleum Resources in respect of the extension, the quantum of which is expected to be within normal parameters for a fee associated with a license extension.

In addition, Lekoil will, subject to securing funding, cover 42.85 percent of the capital expenditures and operating expenses of the Block to first oil, being its 17.14 percent pro rata of an aggregate 40 percent participating interest held by it and the potential funding partner. The potential funding partner will cover the remaining 57.15 percent of the capital expenditures.

Lekan Akinyanmi, Lekoil CEO, commented, “We are pleased to have come to an understanding with Optimum, the operator of the OPL 310 Block. We look forward to working closely with them to unlock significant value for our investors and all stakeholders, not only with the appraisal potential identified at Ogo, but also with the other promising exploration leads readily identifiable in the OPL310 Block.”

Yusuf K. N’jie, Managing Director, Optimum Petroleum, commented, “We are pleased to be moving forward alongside our partner, Lekoil, toward the appraisal and development of OPL 310 and look forward to a successful campaign, achieving our collective objectives for the benefit of our respective stakeholders.”

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China’s national offshore producer CNOOC Ltd (0883.HK) reported a near 19% rise in first-half profit on Thursday, as higher sales of oil and gas offset weaker global oil prices.

The listed arm of state-owned China National Offshore Oil Corp said that it was able to manage the impact on its business of the China-U.S. trade war and CNOOC President Xu Keqiang said the company would boost oil output to offset currency effects amid the escalating trade tensions.

CNOOC said its net profit totalled 30.25 billion yuan ($4.26 billion) for the six months through June. Revenue rose 3% from a year earlier to 108.9 billion yuan.

“The lingering economic and trade disputes, as well as geopolitical instability, may result in further volatility of international oil prices,” CNOOC Chairman Yang Hua said in the company’s results statement.

However, CNOOC expects the Sino-US trade war to have “limited and controllable” impacts, he said.

“The management team is paying close attention to the trade dispute and preparing risk prevention from our end,” said CNOOC President Xu told a briefing.

Total oil and gas sales rose 4.4% to 94.28 billion yuan, with net production of oil and gas up 2.1% at 243 million barrels of oil equivalent.

The offshore oil and gas explorer and producer, one of the world’s most cost-efficient among peers, cut its all-in production cost further to $28.99 barrel, 8.9% below the year-ago level.

Total capital spending reached 33.7 billion yuan in the first six months, up 60.5% on year, in line with the company’s pledge late last year to keep it elevated at record rates over the next few years.

CNOOC also said it will seek more opportunities to enter onshore energy exploration via China United Coalbed Methane, including shale gas, coalbed methane (CBM) and tight gas, Xu said at the briefing.

China’s unconventional gas production will likely reach 41 billion cubic metres (bcm) in 2019, a third of the national gas output, and rise to 46 bcm in 2020, an executive at another Chinese oil giant, CNPC, told a briefing on Thursday.

CNOOC also said it would continue to focus on exploration of mid-to-large sized oil and gas fields. Among the big discoveries made during the first half, Bozhong 19-6, a condensate gas field off north China’s Bohai Sea, has added over 100 million tonnes in proven reserves.

The company continued to make progress at large-scale development projects, including the deep-water Lingshui 17-2 and Liuhua 16-2, both in the South China Sea, CNOOC said, without giving further details.

It had previously aimed to start production at Lingshui 17-2, its first full-owned deepwater gas project, in 2020.

It also expects the upcoming national pipeline company, a combination of pipeline assets owned by the big three state-owned energy giants - CNPC, Sinopec and CNOOC - to benefit its downstream market development and pipeline utilisation.

CNOOC, however, did not give details on the progress of the establishment of the national pipeline company.

https://www.reuters.com/article/us-china-cnooc-result/chinas-cnooc-weathers-volatile-oil-prices-with-19-rise-in-first-half-earnings-idUSKCN1VJ0Z6

The Trump administration has moved broadly to relax Obama-era rules put in place to regulate methane and other greenhouse gas emissions, offshore drilling safety, fuel economy and wetlands rules that impact oil, gas and coal industries.

The rollbacks come amid surging oil and gas production that put the United States output ahead of historical leaders’ Saudi Arabia and Russia. In May, the United States pumped a record 12.4 million barrels per day of crude, according to the U.S. Energy Information Administration.

While the Trump administration has made reducing the regulatory burden on oil and gas companies a priority to drive U.S. energy production and exports, its efforts have drawn rebukes and lawsuits from environmentalists.

Below is a list of changes to federal oil and gas regulations that have been implemented or proposed under President Donald Trump:

EASING METHANE LIMITS

The administration in August proposed rolling back limits on methane emissions at oil and gas operations implemented during the Obama administration.

The proposal is anticipated to repeal regulations put in place in 2016 that limit methane emissions from new oil and gas drilling, transport and storage operations. Natural gas is composed mostly of methane, one of the main pollutants scientists link to climate change.

OFFSHORE DRILLING

In May, the Trump administration unveiled its final plan to roll back offshore drilling safety measures enacted during the Obama administration following the fatal 2010 Deepwater Horizon oil spill. The changes were anticipated to save oil and gas companies $1 billion over ten years.

The Obama administration’s 2016 well-control and blowout preventer rule had required real-time monitoring of operations and certification by third parties of emergency devices. The Sierra Club and other groups sued to reverse the decision, arguing the U.S. had failed to consider potential damage to offshore safety and the environment.

POWER PLANT RULES

In June, the Trump administration finalized a carbon emissions rule for U.S. power plants to help the ailing coal industry and replaced an Obama-era rule targeted at fighting climate change.

The Trump administration’s Affordable Clean Energy (ACE) rule would give states three years to devise their own plans to cut emissions, primarily by encouraging coal-fired power plants to improve their efficiency.

EXPANSION OF OFFSHORE DRILLING

In 2017, the administration ordered a reversal of an Obama-era ban on oil and gas drilling in the Arctic and Atlantic oceans. In 2018, it outlined a proposal to open up the Atlantic, Pacific and new parts of the Arctic oceans to offshore drilling.

Since that plan was announced, six states passed legislation or amendments to restrict offshore drilling. Earlier this year, the plan was sidelined following a court ruling to block drilling in the Atlantic and Arctic.

PARIS ACCORD WITHDRAWAL

Trump announced in 2017 he would withdraw the U.S. from the Paris agreement, which seeks to limit global warming to less than 2 degrees Celsius (3.6 degrees Fahrenheit). Achieving that goal would cut as much as 40% off oil demand by the early 2040s, impacting the industry, according to investment fund Legal and General Investment Management.

In a symbolic move, the U.S. House of Representatives in May approved a bill calling on the president to develop a plan to meet the agreements goals. The U.S. Senate has refused to consider it.

PIPELINE PERMITTING

Trump issued executive orders in early 2019 to limit the ability of states to block interstate energy projects, including pipelines, under a provision of the U.S. Clean Water Act. His orders called for a review of rules requiring state certifications for federally approved interstate pipelines and project.

https://www.reuters.com/article/us-usa-climate-regulations-factbox/factbox-u-s-oil-and-gas-regulatory-rollbacks-under-trump-idUSKCN1VJ2BP

Norwegian energy firm Equinor has announce it has completed the sale of Swedish exploration oil and gas company Lundin Petroleum.

The deal for Equinor’s 16% shareholding in Lundin has been sold for almost £600 million for a 2.6% direct interest in the Johan Sverdrup project.

The transaction was first announced on July 7 2019.

The deal totaled £589m.

The first part of the deal, an acquisition of around 54.5 million shares in Lundin Petroleum AB from Equinor ASA, concluded on August 5 and followed the approval of the transaction in Lundin Petroleum AB’s Extraordinary General Meeting on July 31 2019.

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The second part, Equinor Energy’s acquisition of the 2.6% in the Johan Sverdrup field from Lundin Norway AS, concluded on 30 August.

The Johan Sverdrup field, 100 miles west of Stavanger, has estimated resources of up to 3.1billion barrels of oil equivalent.

https://www.energyvoice.com/oilandgas/206578/equinor-completes-sale-of-stake-in-lundin-petroleum/

International compressor supplier TMC Compressors of the Seas (TMC) has been awarded a contract to supply a compressed air system to Golar LNG’s Gimi FLNG vessel, which will operate offshore Mauritania and Senegal.

FLNG Gimi is currently undergoing a conversion from a Moss LNG carrier to a floating LNG (FLNG) production unit at Keppel Offshore & Marine’s Shipyard in Singapore.

Keppel received the Final Notice to Proceed from Gimi MS Corporation, a subsidiary of Golar LNG, to start full conversion works for the Gimi FLNG back in April 2019. The vessel is scheduled for delivery in 1H 2022.

TMC said on Monday that its scope of work includes manufacturing and delivery of seven large Smart Air compressors to be installed on board the FLNG Gimi. The company has not disclosed the value of the contract.

“Our Smart Air compressor technology offers precise control of the compressor speed, which means that they can run more efficiently than traditional compressors. As a result, Smart Air compressors offer up to 50 percent reduction in energy consumption, with similar reduction in CO2 emissions and operational costs,” says Hans Petter Tanum, director of sales and business development at TMC.

When completed, the Gimi FLNG will be stationed at a nearshore hub located on the Mauritania and Senegal maritime border as part of the first phase of the BP-operated Greater Tortue / Ahmeyim project. The Gimi FLNG is designed to produce an average of approximately 2.5 million tonnes of LNG per annum.

In 2017, TMC won a contract to deliver a similar Smart Air compressed air system to Golar LNG’s FLNG Hilli Episeyo.

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London — Planned refinery turnarounds in Europe have been ramped up, with refineries in both Northwest Europe and the Mediterranean undergoing works, coinciding with a large-scale maintenance in Russia.

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A minor fire at the Dutch Zeeland refinery last week was brought under control quickly with no impact on operations.

Greek refiner Hellenic said that despite "a weak refining environment"

its Q2 results were positive "on account of continued strong refining performance," adding that it posted "the highest petchems contribution on record."

The international refining macro environment "deteriorated to its lowest level in the last five years," Hellenic said in its Q2/H1 results, noting "multi-year low" benchmark refining margins and problems with Russian crude supplies due to contamination and the outage of the Druzhba pipeline.

The flexibility of its refineries "to process a wide range of crude grades" enabled "uninterrupted supply" and allowed it to "capture opportunities in medium/light crude pricing," it said.

Of the IMO's new 0.5% sulfur cap for bunker fuel, Hellenic said it is "on track with its plans to be able to deliver very low sulfur fuel oil by the beginning of 2020" and that the new bunker fuel could be available in November. It recently conducted an extensive test of new crude grades at the Aspropyrgos refinery, "yielding positive results, in terms of both quality and specs of the new 0.5% fuel oil, as well as the operation of the refinery's conversion units," it said. It plans to change the crude slate by processing more light crudes, such as Azeri, Saharan and some American crude, it said during a conference call.

All petrochemical units at Germany's Burghausen refinery are gradually restarting following a technical incident and will be back in operation by Sunday, the company said late last week. First deliveries of propylene have also commenced, it said. Due to the incident on August 24, "no ethylene and butadiene are currently being delivered from the Burghausen refinery," owner OMV said, adding that the facility's customers have been informed. According to local media, the glitch occurred at the cooling system of the ethylene plant. During the restart, flaring can be expected.

NEAR-TERM

NEW AND REVISED ENTRIES

--Maintenance of the FCC unit at Greece's Corinth refinery will impact operations "for the second half of 2019", the company said in its H1 report.

According to traders the maintenance will take place in September.

--There will be planned maintenance shutdown at Greece's Elefsina refinery in Q4.

--Slovnaft said that its Bratislava refinery is in "full operation" after completing "its historically largest turnaround" on 21 production units. New projects implemented during the maintenance "are expected to contribute to the more efficient, reliable and safe operation of the refinery." Maintenance will continue on three petrochemical units this autumn with part of the projects focusing on "reducing nitrogen emissions into atmosphere and on modernization".

--The short halt of the fluid catalytic cracker unit at ExxonMobil's Fos refinery didn't have any impact on production and supply, the company said.

The unit at the Fos refinery in southern France was restarting early last week after the brief shutdown. The unit's compressor was halted late on August 23 for safety reasons.

--The API refinery in the central Italian coastal town of Falconara Marittima has completed maintenance on its platforming and hydrogen 1 units, and these are now fully operational, a source close to the plant told S&P Global Platts. The maintenance work started in late July.

--Planned maintenance on Portugal's Sines atmospheric distillation unit has started, with work due to last 40-50 days, a spokesman said in late August.

The company previously said it will use the halt to increase efficiency and conversion ability of the refinery, as well as improving its refining margin. The conversion units at the refinery will continue to work at full capacity during the outage and refining margins will not be affected, CEO Carlos Gomes da Silva said previously. The company said its entire refining system, comprising Sines and the 110,000 b/d Matosinhos refinery, should be fully operational in the whole fourth quarter, allowing the company to capture a forecast increase in refining margins due to the impact of new International Maritime Organization marine fuel sulfur regulations coming into force next year.

--Germany's Rhineland said that Godorf is preparing for the large-scale maintenance scheduled to start in September and last until mid October. It has previously said the works will be running from September 2 to October 10. The 327,000 b/d refinery consists of the Wesseling (south) and Godorf (north) sites. The maintenance includes shutdown, inspection, cleaning and repair of the facilities. Although a large part of the units will be halted, supply of products will not be affected "thanks to good planning and storage," it said.

--The northern Scholven part of BP's Gelsenkirchen refinery in Germany is in the process of undergoing its scheduled maintenance. The maintenance could result in flaring, the company said. Restart will begin in mid-October.

Various units would be shut down for around seven weeks. The refinery consists of the Horst and Scholven sites, with Horst representing around one-third of total capacity.

--Total's Gonfreville refinery near Le Havre, France, is starting its scheduled maintenance September 4, the company said. The works will last around two months. The large-scale maintenance, which takes place once every seven years, follows the maintenance at the petrochemical site which took place last year. Preparations for the turnaround have been going on for the last three years.

--The maintenance at Preem's Lysekil refinery near Brofjorden will take place as planned, starting at the beginning of September, the company said. The works are due to continue until mid-November. Separately, the refinery experienced more than a week of production disruptions in May, the company said in its second-quarter results. "In the beginning of May 2019, there were production disruptions at our Lysekil refinery related to leakage in our crude oil distillation unit. The unit was repaired and fully back in operation after 11 days of downtime," the Stockholm headquartered group said.

--A topping unit at Russian energy giant Lukoil's ISAB refinery in Sicily remains offline amid weak product demand, sources close to the refinery told S&P Global Platts in late August. The refinery had completed upgrades and ordinary maintenance on the unit at the northern plant in the past months, though it was not restarted "for market reasons," the source said. At the time, it was indicated the timing of the maintenance works were related to market conditions. ISAB was not immediately available to comment. A turnaround is scheduled for the refinery's southern plant in the autumn. Preparations for the maintenance will start in September, with the plant expected to go offline for some 40 days from October.

--A Topping 3 crude unit that had been under maintenance from June at the Milazzo refinery in Sicily was restarted in late July and is now operating as usual, trade union sources told S&P Global. The Topping 3 unit had been placed offline on June 21 for the upgrade and maintenance works. The plant is scheduled to carry out 45 days of maintenance work on its FCC unit and ancillary plants starting October 1, a source told S&P Global.

--Germany's Bayernoil refinery in Bavaria, which was taken offline following an incident last September, is ramping up production, with a number of units back online, and the refinery getting back to normal, Russia's Rosneft official said during an investor call for H1 results presentation. The reformer, fractionation and bitumen production units are already back on line and in September diesel capacity will be added. The refinery said previously that its restart began in May with the steam boiler and that the remaining units would be coming on stream over the course of the summer. The refinery was halted following an explosion in a unit at the Vohburg site and a subsequent fire in the early hours of September 1, 2018. Bayernoil consists of the Vohburg and Neustadt sites, which are closely interconnected.

EXISTING ENTRIES

--Eni expects full operations at its Sannazzaro de Burgondi refinery in northern Italy in the third quarter, the company said in its Q2 report. It had previously said that it expects to restart in September the Eni Slurry Technology (EST) unit, which was placed offline amid damage from a fire almost three years ago. Repair works on two EST plant units have been ongoing since the fire in 2016. Eni's Sannazzaro will start maintenance work on its Line 2 between September and October, sources said.

--Mineraloelraffinerie Oberrhein (Miro) expects to restart the 12,500 mt/day fluid catalytic cracker at its refinery in Karlsruhe, Germany, in 3-4 weeks, a company spokesperson said. The FCC was shut down August 7 following a technical issue.

--Israel's Ashdod refinery is due to undergo maintenance in October. As part of the works it aims to carry out upgrades ahead of the IMO 2020 low sulfur cap on bunker fuel. "We are investing in new facilities in the Paz Ashdod Refinery which will improve its yield," it said.

--Finland's Neste has scheduled a four-week decoking maintenance at Production Line 4 at Porvoo in September-October which would have a "negative impact" on the segment's operating profit, "mainly in the fourth quarter". It expects high utilization rates in Q3, "except for normal unit maintenance." In Q4 it has scheduled a catalyst change at the Rotterdam renewable products refinery.

In 2017 Neste completed the integration of the Porvoo and Naantali refineries.

--Klesch's Heide refinery will restrict operations for inspection and maintenance until October 6, the company said early August. The reduction in operations started for checks in advance of the main work, which will begin at the start of September and will last through October.

--Italy's Sarroch forecasts refinery runs at 26 million-27 million barrels for both the second and third quarter, while it expects runs to drop slightly in the fourth quarter to 25 million-26 million barrels. For the full year, Sarroch forecasts runs of 96 million-99 million barrels. In Q4, the refinery is scheduled to carry out maintenance on its north plants, its visbreaking unit, its RT2 topping unit and V1 vacuum unit, according to a company presentation on its Q1 results. The refinery will also carry out work on its petrochemicals plant.

FUTURE

EXISTING ENTRIES

--Repsol 2019 maintenance plans include hydro-treatment unit and hydrocracker at Cartagena in September; partial works at Puertollano in October and November, as the company is carrying out an extensive digitalization upgrade at the plant this year and will carry out turnarounds at the cracker and chemical derivative plants at the end of 2020; and petrochemical works at Tarragona in Q4. The cracker at Tarragona would undergo maintenance in Q4 2019, pushed back from Q3. At A Coruna, the FCC and VDU set to undergo maintenance this year. Repsol said it will invest Eur69 million in four projects that will upgrade the fluid catalytic cracker at A Coruna during 2020 and increase the refinery's production of polymer grade propylene. The work will take place during a scheduled maintenance halt at the start of 2020.

--Finland's Neste is preparing for a major turnaround at Porvoo in 2020.

--Total will invest Eur150 million at its Leuna refinery in Germany. The investment into an upgrade project aims to reduce the production of heavy products, demand for which decreases, and increase the production of methanol, which is an important feedstock for the chemical industry. This will deepen the integration of the refinery and the petrochemical operations and increase the competitiveness of the plant. The methanol production will increase as a result of increased output from the visbreaker unit and an upgrade of the POX/Methanol plant. Work will continue until 2021, with the major part done in the 2020 major shutdown of the refinery where another Eur150 million will be invested.

--The next major turnaround at Preem's Gothenburg refinery in Sweden will be in 2021.

--Saras will carry out maintenance and upgrade works on the 90,000 b/d FCC unit at its Sarroch refinery in 2020. It will carry out a full maintenance shutdown, conducted every 10 years, in 2021.

--Sarpom's refinery in Trecate, Italy, is scheduled to undergo a large-scale, two-month general maintenance cycle in 2020 -- of the type carried out at the plant every three to four years -- a source close to the refinery said.

--A shutdown may be carried out at Portugal's Porto at the end of 2019 or early 2020 for under three weeks for the atmospheric distillation unit, where it needs to install heat exchangers.

--Rompetrol's Petromidia refinery will have its next general maintenance in 2020.

--Spain's Cepsa has moved a step closer to permanent closure of its refinery on Tenerife after signing an agreement with the regional authorities of Santa Cruz, Tenerife, to transform the site into a mixture of public space and real estate. The complex, which has been in operation for nearly 90 years, refined its last oil in 2014, having been previously idled in 2013 for "economic reasons."

--The next major maintenance at the Netherlands' Zeeland will be in 2020. The refinery has expanded its hydrocracker with the addition of third reactor, the company said. The refinery started work in June 2018 on an expansion of the hydrocracker, by working to add the third reactor. The reactor will be connected to the existing installation in 2020.

--Romania's Petrobrazi will undergo its next big turnaround in 2022.

UPGRADES

NEW AND REVISED ENTRIES

--Greece's Motor Oil Hellas has approved an investment project for the construction of a new naphtha treatment complex at its Corinth refinery, it said in its 2019 H1 report. The new complex, which will contribute to increased production of gasoline, kerosene and hydrogen, is scheduled for completion in 2021.

--Swedish refiner Preem is "evaluating a potential investment in a residue hydrocracking plant" at the Lysekil refinery, it said. The investment would be aimed to "upgrade as much heavy oil as possible into sulfur-free gasoline and diesel fuels to help meet rising demand after IMO 2020," a company spokesman said.

--Netherland's Zeeland refinery has had the third reactor for the hydrocracker's expansion delivered. The refinery started work in June 2018 on an expansion of the hydrocracker, by working to add the third reactor. The reactor will be connected to the existing installation in 2020.

--Poland's second-largest refiner Grupa Lotos said the coking complex -- a key element of its EFRA modernization program -- was complete and ready for start-up with some facilities placed in service and some ready for testing and trials. "All facilities covered by the EFRA Project are scheduled to be commissioned by the end of Q4 2019. Engineering design, procurement and construction works under the EFRA Project have been completed," Lotos said in its Q2 financial results. The coking complex, comprising a delayed coking unit, a coker naphtha hydrotreating unit, and coke storage and logistics facility would allow the refinery to stop producing heavy fuel oil.

EXISTING ENTRIES

--Repsol said it will invest Eur69 million in four projects that will upgrade the fluid catalytic cracker in A Coruna during 2020 and increase the refinery's production of polymer grade propylene. The company has received the necessary licenses from local authorities to carry out the work in its conversion units, it said. The FCC investment will total Eur40 million. The first project (G-52) will be directed towards energy efficiency and CO2 reduction, while G-53 will reduce the atmospheric particle emissions form the unit. At the same time, project G-54 will involve the installation of a new compressor in the gas recovery unit and the substitution of steam turbines for electric motors in both that unit and the FCC. The work will take place during a scheduled maintenance halt at the start of 2020, the company said. Besides the work on the conversion units, Repsol will spend Eur29 million on project G-55 which includes the installation of a new 80-meter splitter, with work also to commence in 2020. The new unit would be online towards the end of next year, it said.

--Germany's Rhineland has started the construction of a new hydrogen production plant, using electrolysis, at its Wesseling site. The Eur16 million investment project, due for completion in 2020, will generate hydrogen from electricity rather than natural gas, and thus also contribute to reduced CO2 emissions. It will produce up to 1,300 mt/year hydrogen when operating at peak rates. "Oil products will continue to play an important role in the decades ahead, and this project means we will be able to make more and cleaner fuels, bitumen and base chemicals," said Frans Dumoulin, director of the Shell Rheinland Refinery in a statement. "At the same time, we want to contribute to accelerating the use of hydrogen in transport and other sectors." The 327,000 b/d refinery consists of the Wesseling (south) and Godorf (north) sites.

Separately, the refinery has received permission to start construction of a new power plant at Godorf. Construction will start immediately with the new plant scheduled to go onstream in 2021. As part of the modernization, Shell is converting the power plant from oil to gas and the new plant will have significantly lower emissions.

--A Spanish press report citing the Andalucia region's chief officer for finance, industry and energy, Juan Bravo, said Cepsa's Eur1 billion "bottom of the barrel" project at its San Roque refinery may be delayed. The report in ABC de Sevilla said the project was being held up by an unspecified administrative procedure delaying the start of work. A Cepsa spokesman declined to comment. The report says the project may be held up a year and start in 2020, instead of 2019 as planned. The project entails a new hydrocracker at the site to adapt it to producing lighter products by increasing the conversion factor and also to increase the output of gasoline blending components. The upgrades are currently expected to be concluded by 2022, adding $1.4/b to its refining margin and increasing refining capacity by 36,000 b/d. The output of diesel should increase to 55% from 40% once the project is concluded. Cepsa is also to revamp the Isomax unit, fluid catalytic cracker and alkylation units and construct a methylene unit (Sorbex II) at San Roque, which will double production capacity, investing Eur1 billion through to the end of 2019 as it aims to boost conversion rates and improve technology and sustainability. Cepsa said it raised non-aromatic solvents output by 30,000 mt/year in 2018 and started work on a fixed bed alkylation plant, which is expected to start up in 2020.

--ExxonMobil said it has "made a final investment decision to expand" the Fawley refinery in the UK to increase production of ULSD by 45% or 38,000 b/d.

The more than $1 billion investment includes a hydrotreater to remove sulfur from diesel, supported by a hydrogen plant. The investment "will help reduce the need to import diesel into the United Kingdom, which imported about half of its supply in 2017," the company said. The construction, which is subject to a local planning approval, is set to begin in late 2019 with start-up expected in 2021.

--McDermott International has been awarded a contract for engineering, procurement and construction management services for the upgrade of the hydrocracker at Czech Litvinov refinery. McDermott had previously completed the feasibility study and basic engineering design. The completion is expected for Q2 of 2020. Work on the project will begin immediately.

--Russian Lukoil plans to invest in its ISAB refinery in southern Italy and has also dropped plans announced in 2017 to sell the plant having not received suitable offers, the company and union sources said. Lukoil will invest $60 million in upgrades, including two hydrodesulfurization units, which will allow the refinery to fully move to the production of Euro 5 diesel and halt output of Euro 3 and Euro 4 product.

--Cepsa said it will carry out upgrades to its aromax and hydrocracker units at Huelva in 2019. It is also carrying out an aromatics optimization project at the refinery.

--Croatia's INA will concentrate its refining in Rijeka, which will also be upgraded, and convert the smaller Sisak facility into an industrial site as part of its Downstream 2023 New Course program and 2019 business plan, the company said. The company plans to invest more than HRK 4 billion ($615 million) in a delayed coker project at Rijeka, a new port with closed petcoke storage and increased overall complexity that will make Rijeka "a top level European refinery." A final investment decision on the delayed coker project will be taken this year, with commissioning earmarked for 2023 "given that all the prerequisites that will assure return on investment will be met."

--The delayed coker at the Pancevo refinery, currently under construction, will be launched in third quarter of 2019, Kirill Tyurdenev, the managing director of NIS, said in Gazprom Neft's in-house magazine. As a result the depth of processing will reach 99.2% and the refinery will produce 500,000 mt more light products. The Nelson index will increase to 9.6. The light products yield would increase to 85% from 75%. Gazprom Neft has previously said the delayed coker will have 2,000 mt/day capacity.

--Total is considering building intermediate feedstock desulfurization units and a hydrogen unit at France's Donges, but the investment depends on rerouting a railroad track that currently crosses the refinery.

--Poland's Plock refinery aims to complete a new visbreaker unit by the end of 2020.

--Israel's Haifa District Court has rejected an appeal by Haifa municipality along with six other neighboring communities and environmental groups against the proposed expansion of the Bazan refinery.

LAUNCHES

EXISTING ENTRIES

--Turkey's Ersan Petrol plans to start construction of its 1.4 million mt/year Nazli refinery at Kahramanmaras in southeast Turkey in mid-2020, with the plant expected to begin operations in less than four years, company owner Ecvet Sayer said. "We expect to reach financial closure for the project this summer and after that start the FEED studies which will take about nine months," he said. Sayer did not comment on reasons for the delay to the project, which had previously been expected to start construction by the end of 2018, but the past 18 months have seen Turkey pass through a major economic crisis that caused the Lira to fall by 47% against the dollar. The refinery is expected to produce diesel, jet, fuel oil, gasoil and LPGs.

--Dutch Hes International (former Hestya Energy) aims to start operations at a unit of the currently closed Wilhelmshaven refinery in Germany "later this year," it said in early January. The Netherlands-based company had previously said it would operate the unit, which it declined to name, under a tolling agreement. According to traders, it is the VDU that is likely to be restarted in 2019 and used for producing low sulfur fuel oil ahead of the 2020 IMO requirement for low sulfur bunker fuel.

--Azerbaijani state oil company Socar is considering the development of a second refinery in Turkey, in addition to its existing 214,000 b/d Star refinery at Aliaga on Turkey's central Aegean coast. Development of a second refinery would be necessary if the company decides to go ahead with plans for a second petrochemical plant at its existing Petkim facility. A final investment decision is expected in March.

--Elza Turner, elza.turner@spglobal.com

--Edited by Jonathan Fox, jonathan.fox@spglobal.com

http://plts.co/ziY050vTpDM

The domestic fuel prices are determined broadly by the global crude oil and rupee-dollar forex rates.

Prices of petrol and diesel were unchanged across the four metro cities on Monday. Petrol is priced at Rs. 72.01 per litre in New Delhi, Rs. 74.71 per litre in Kolkata, Rs. 77.67 per litre in Mumbai and Rs. 74.80 per litre in Chennai, according to state-run Indian Oil Corporation's (IOC) website, iocl.com. Diesel rates stood at Rs. 65.25 per litre in New Delhi, Rs. 67.63 per litre in Kolkata, Rs. 68.41 per litre in Mumbai and Rs. 68.94 per litre in Chennai.

State-run oil marketing companies Indian Oil, Bharat Petroleum and Hindustan Petroleum revise fuel prices with effect from 6 am on a daily basis.

The domestic fuel prices are determined broadly by the global crude oil and rupee-dollar forex rates.

Oil prices weakened on Monday after new tariffs imposed by the United States and China came into force, raising concerns about a further hit to global growth and demand for crude, reported news agency Reuters. Brent crude dropped 16 cents to $59.09 a barrel in intraday trade.

Meanwhile, domestic petrol prices came down in August. The prices were decreased in the range of 78-86 paise per litre in the four metros in August, according to data from IOC's portal.

On July 31, petrol prices were at Rs. 72.86 per litre in New Delhi, Rs. 75.50 per litre in Kolkata, Rs. 78.48 per litre in Mumbai and Rs. 75.66 per litre in Chennai. On August 31, the petrol price stood at Rs. 72.01 per litre, Rs. 74.71 per litre, Rs. 77.67 per litre and Rs. 74.80 per litre respectively.

Diesel prices were also slashed in the range of 56-77 paise per litre across metros in August.

On August 31, diesel rates stood at Rs. 65.25 per litre in New Delhi, Rs. 67.63 per litre in Kolkata, Rs. 68.41 per litre in Mumbai and Rs. 68.94 per litre in Chennai.

Get Breaking news, live coverage, and Latest News from India and around the world on NDTV.com. Catch all the Live TV action on NDTV 24x7 and NDTV India. Like us on Facebook or follow us on Twitter and Instagram for latest news and live news updates.

https://www.ndtv.com/business/petrol-diesel-rates-today-heres-how-much-you-pay-for-petrol-and-diesel-today-2094390&ct=ga&cd=CAIyGjFhODM5OTgwNmE5N2Q2NjA6Y29tOmVuOkdC&usg=AFQjCNFZ1Ty-JaFp7BuzEERXn2Ybn0Rkd

An independent Russian producer has made a foray into China’s market for liquefied petroleum gas (LPG), jostling with Middle Eastern countries for what could be a lucrative foothold, market data showed and traders said.

China is one of the world’s largest importers and consumers of the fuel. Key suppliers to the country are the United Arab Emirates, Qatar, Kuwait and Saudi Arabia, which jointly account for more than 60% of China’s LPG imports.

Russia is one of the top oil exporters to China and is set to launch a gas export pipeline connecting the two countries by the end of this year. Its LPG supplies to China are small at this stage but Moscow is expanding production.

According to rail statistics, Irkutsk Oil Co, known by the Russian acronym INK, shipped around 2,300 tonnes of propane and butane mixture by train toward the Far East Gas terminal in northeastern China between Aug. 16 and 26.

Despite past attempts by Sibur and Gazprom Neft, high logistics costs have so far prevented LPG exports to China from occurring regularly. But INK is located much closer to the Russia-China border than those firms, giving it a comparative advantage.

INK started producing LPG, which can be used in cars or to produce electric power and petrochemicals, in 2017 and began exports a year later. Until recently, INK was exporting LPG only to Europe.

It cranked up LPG output tenfold year-on-year in the January-June period to 77,000 tonnes thanks to the construction of a pipeline to a railway loading facility in Ust-Kut, eastern Siberia.

INK plans to increase LPG output to as much as 1 million tonnes per year by 2020-2021. INK is controlled by its management, with Goldman Sachs and the European Bank for Reconstruction and Development among minority shareholders.

INK declined to comment.

MORE FUEL EXPORTS TO CHINA

Traders said Swiss trader Avestra Chemical, a co-owner of the Far East Gas terminal, had been in talks with other Russian companies, including Sibur, Gazprom and Rosneft, about LPG supplies to China.

Igor Berezin, chief executive of Avestra Chemical, confirmed to Reuters that the Far East Gas terminal had received its first LPG cargoes from Russia. He declined to comment further.

The terminal, built last year, is set to boost its annual transhipping capacity to as much as 3 million tonnes in coming years from around 1.8 million tonnes currently.

China’s LPG imports rose 3.4% year-on-year in the first half of 2019 to 9.785 million tonnes, Chinese customs data shows.

IHS Markit, an information provider, expects LPG consumption in northeastern Asia to exceed 110 million tonnes per year by 2025 from 80 million tonnes in 2018 thanks to the launch of new processing units in China.

https://www.reuters.com/article/us-russia-china-lpg/russian-firm-battles-mideast-for-chinese-petroleum-gas-market-idUSKCN1VK1EE

Asian spot prices for liquefied natural gas (LNG) were steady this week as spot demand from Japanese buyers stockpiling ahead of winter soaked up supply offered from Australia and Malaysia.

Spot prices for October delivery to Northeast Asia are estimated to be about $4.70 per million British thermal units (mmBtu), steady from last week, said several sources that participate in the market.

Japan’s Tohoku Electric likely bought a cargo for delivery over Oct. 16 to 20 at $4.60 to $4.70 per mmBtu, an industry source said, though this could not immediately be confirmed.

Japanese buyers have been seeking cargoes in the spot market for fourth quarter delivery as they take advantage of low prices and as hot weather likely recently drew down inventories, said several industry sources.

Japan’s Hokuriku Electric bought a cargo for delivery in second half of November from Malaysia’s Petronas, sources said.

The utility started importing LNG late last year and has been buying cargoes from Petronas, though its requirements have not been regular, one of the sources said.

Japan’s Hokkaido Electric Power also sought a cargo for delivery in November.

Demand was also firm from India with Torrent Power and Indian Oil Corp each seeking a cargo for delivery in October, sources said.

An earlier one-year requirement by Essar Group for 12 cargoes was canceled, sources added.

Still, despite the demand, buyers’ expectations of prices for cargoes were still low, one trading source said.

Supply was also ample as Australia’s Ichthys LNG plant offered a cargo for October while Malaysia’s Petronas closed a tender offering a cargo from its Bintulu plant, industry sources said.

Indonesia’s Donggi-Senoro export plant offered two cargoes for loading in November and December.

Egyptian Natural Gas Holding Co (EGAS) offered three cargoes for loading from the Idku plant in September in a tender which was later canceled due to low bids, sources added.

In the United States, Freeport LNG’s start-up is approaching, with up to two idle vessels ready at the Freeport anchorage area, Kpler analysts said in a note this week.

https://www.reuters.com/article/us-global-lng/japanese-winter-appetite-mops-up-some-of-surplus-cargoes-idUSKCN1VK161

The United States, Poland and Ukraine agreed on Saturday to enhance cooperation over secure gas supplies in the region which still relies on Russia.

“We’re helping Poland to reduce its dependence on Russian gas,” U.S. Energy Secretary Rick Perry told a news conference in Warsaw after meeting officials from Poland and Ukraine.

The Polish government official responsible for energy infrastructure, Piotr Naimski, said Poland, which has increased purchases of liquefied natural gas (LNG) from the United States in recent years, would be able to send six billion cubic meters of gas to Ukraine starting from 2021 compared to the current capability of 1.5 bcm.

“We will take every effort to diversify gas supplies to Ukraine, which is now completely dependent on Russian deliveries,” Naimski told the same conference.

Perry, Naimski and Ukraine’s Secretary of National Security Oleksandr Danylyuk signed a memorandum of understanding to enhance security of gas supplies in the region via LNG supplies from the U.S. through Poland’s and Ukraine’s infrastructure which still has to be expanded.

Under a policy it calls energy dominance, the administration of President Donald Trump, who canceled his trip to Warsaw earlier this week, is seeking to slash domestic regulations on energy production to boost oil and gas exports to allies and trade partners.

It is seeking to offer Europe alternative sources of gas to fuel sent via pipeline from Russia, which is generally cheaper than U.S. LNG, but has not always been reliable with Russia at times stopping deliveries to Ukraine and parts of Europe during pricing disputes.

More than a third of Russia’s gas exports to the European Union cross Ukraine, which traditionally uses some of the gas pumped by Russia to European consumers for its own needs in eastern and central regions.

But the Russia-Ukraine gas transit agreement is due to expire in January and Ukrainian energy authorities are worried that Moscow could stop gas supplies through Ukraine, leaving some Ukrainian regions without gas in winter.

Also Poland, which is seen as one of Washington’s closest allies in Europe, still buys most of the gas it consumes from Russia, has taken steps to cut this reliance after 2022 when its long-term deal on gas supplies from Gazprom (GAZP.MM) expires.

Poland’s imports of LNG, including from the U.S., via the Baltic Sea terminal at Swinoujscie have jumped in recent years as part of a wider plan to cut reliance on Russian supplies.

Earlier this week Poland’s state-run gas firm PGNiG (PGN.WA) said that it bought a cargo of liquefied natural gas from the U.S. and sold it to Ukraine.

https://www.reuters.com/article/us-poland-usa-energy/u-s-to-help-poland-ukraine-disconnect-from-russian-gas-idUSKCN1VL0HH

Papua New Guinea sticks to gas deal with Total for $13 bln project

Sonali Paul

4 MIN READ

* Papua LNG pact needed for $13 bln gas expansion project

* Government review sought more benefits from Papua LNG

* Total commits to consider potential future benefits

* Oil Search shares rise 2% in flat market (Recasts with PNG government’s decision)

By Sonali Paul

MELBOURNE, Sept 3 (Reuters) - Papua New Guinea said on Tuesday it will honour a gas deal that Total SA signed with a previous government for a $13 billion plan to expand gas exports, after securing minor concessions from the French company.

The decision removes uncertainty over the plan to double liquefied natural gas (LNG) exports from the Pacific nation that arose after new Prime Minister James Marape came to power in May promising to win more benefits for the impoverished country.

The Papua LNG gas agreement is one of two agreements needed for Total and its partners, Exxon Mobil Corp and Oil Search Ltd, to go ahead with the LNG expansion plan.

“The government has now cleared Total to proceed full steam ahead with the implementation of the Papua Gas Project,” Petroleum Minister Kerenga Kua said in a statement.

Doubts about the gas deal escalated in August, when the government suddenly called for talks to revise the agreement.

Kua said Total had made some concessions, promising to prepare a detailed plan outlining how much local equipment and services would be used in the project and to negotiate with any third party wanting access to the project’s petroleum pipelines.

It would also be willing to negotiate for Papua New Guinea to take a stake in the pipelines after the state has repaid all its loans and costs on the project, and would consider buying LNG carriers in a joint venture with the state.

“Most of these are substantial new concessions on potential future benefits,” Kua said.

The companies had insisted that the Papua LNG gas agreement that Total signed in April should be honoured, and Oil Search warned in August that costs on the project could rise if it was delayed by prolonged talks.

An analyst said the government had capitulated to Total, winning only non-committal offers to consider future steps that might benefit the country.

“This is a big win for the industry, but they can’t say that, because they need to let the prime minister and Kua save a little political face,” said the analyst, who declined to be named as he had yet to publish a note to clients.

The three companies welcomed the government’s decision.

“We are looking forward to working with the Government of PNG to conclude the required gas agreement for the P’nyang project,” Exxon Mobil said in an emailed comment, referring to the second of the two agreements needed.

Shares in Oil Search, which have dropped over the past three months amid uncertainty over the gas agreements, closed 2.1% higher shortly after the government’s announcement in a flat broader market.

“There should be a handsome re-rating,” Adrian Prendergast, an analyst at Morgans, said a day ahead of the announcement.

“In the time the political developments have been happening it (Oil Search) has really derated more than the total value that we place on this expansion.”

At Monday’s close, Oil Search shares were down about 14 percent since the previous prime minster stepped down.

Reporting by Sonali Paul; Additional reporting by Nikhil Kurian Nainan in Bengaluru; editing by Richard Pullin

Our Standards:The Thomson Reuters Trust Principles.

Bringing together leading companies for a unique event shaped to tackle the topics of diversity, inclusion and empowerment in the global energy sector.

LONDON, UNITED KINGDOM, September 3, 2019 /EINPresswire.com/ -- You will hear from key players, decision-makers and experts in the field as they share their views, insights and successes in the areas of diversity, inclusion and empowerment with the aim of highlighting what can be done to progress people and communities within energy companies globally.

The Summit will conclude with the London Networking Reception and is open to all registered attendees.

Enquire now about the Sponsorship & Exhibition packages available that suit a broad range of companies in the upstream sector. This platform will afford you an excellent opportunity to enhance your companies' prominence and visibility to the decision-makers and industry professionals at this prestigious energy industry event in the heart of London.

Confirmed Speakers:

Gwen Parry- Jones, OBE, Chief Executive Office, Magnox

Chi Onwurah, Labour MP for Newcastle upon Tyne Central, Shadow Minister for Industrial Strategy Science & Innovation

Dr Sarah Peers, Deputy President, International Network of Women Engineers and Scientists

Abbie Sampson, Director of External Affairs, Energy UK

Sandy Stash, Executive Vice President - Safety, Operations, Engineering, and External Affairs, Tullow Oil

Lamé Verre, Senior Regional Manager| Treasury

Credit & Collections, Haliburton

Mary Munroe, Geologist and I&D Focal Point for the Geoscience Function, Woodside Energy

Rita Hausken, Leadership Strategist & Coach

Event Highlights:

• Uncover the leading edge on diversity, inclusion and empowerment in energy • Hear from energy companies leading the way in diversity

• High-level C-Suite networking

• Excellent Sponsorship & Exhibition opportunities • Shape the debate on diversity, inclusion and empowerment in the energy sector

• Attend the London Networking Reception

Attendees:

• Energy Company Decision Makers

• Chief Executive Officers

• Heads of Global Capability • Heads of Diversity & Inclusion

• HR Directors • Energy Professionals

Conference fees include participation to the events specified, online presentations post-event, refreshments & luncheons and drinks reception.

Organised by Frontier, delivering exclusive and focused global events, awards and networking platforms for the oil, gas and energy sector.

Contact: Gayle Meikle - info@diversityenergysummit.com

Tel: +44 20 71938224

For more information please visit their website

http://www.einnews.com/pr_news/495353747/join-the-conversation-on-diversity&ct=ga&cd=CAIyGmVlZjU3YTM5NTlmOTE2ZDg6Y29tOmVuOkdC&usg=AFQjCNH-Vl_vA_Hcuzu4uzEGPjTOfl3_N

Aker Solutions launches Intelligent Subsea field design system

9/3/2019

LYSEKER, NORWAY - Aker Solutions today launches its Intelligent Subsea offering, designed to accelerate field development and maximize performance.

The industry has standardized, simplified and reduced the size of equipment in recent years, but a further step-change is needed to drive a sustainable future for the subsea industry and the world it serves.

With Aker Solutions’ intelligent subsea approach, the time it takes to generate optimal subsea field layouts can be cut by 75 percent and the cost of field development capex can be halved. Accelerated field development is achieved by combining Aker Solutions’ modular, optimized and configurable subsea equipment with automated design, which can reduce engineering hours by up to 70 percent.

Intelligent Subsea addresses the current and future needs of subsea production by combining three core value propositions:

Adopting an integrated approach to field design where both the subsea and topside systems are optimized and concepts can be rapidly developed with the aid of advanced digital tools

Standardized and digitally-enabled products that can be rapidly configured to customers’ needs and are delivered with accelerated timelines - reducing the time to first production

Maximized life of field performance with enhanced recovery and extend field life enabled by condition monitoring, predictive maintenance and simplified system enhancement as the field matures

"Digitalization of our work process and new applications are transforming field design, radically accelerating development and delivering actionable insight to maximize performance through the life of a field," said Aker Solutions CEO Luis Araujo. "Our system thinking and intelligent solutions are a revolution in subsea developments. Intelligent Subsea is enhancing recovery, saving cost and increasing value through life of field."

"With our industry-leading all-electric and subsea gas compression technology, we extended the frontier for subsea production. We believe Intelligent Subsea will set a new frontier for customer value in projects around the world," said Araujo.

Related News ///

FROM THE ARCHIVE ///

http://ow.ly/CaQq50vUC9d

As tens of thousands oil and gas professionals gather in Aberdeen for the biannual SPE Offshore Europe conference & exhibition, the UK offshore scene is poised for a timely comeback.

Rystad Energy expects a new wave of UK field development projects to be sanctioned towards 2022. The independent energy research and consulting firm forecasts that final investment decisions (FIDs) could be reached on as many as 38 new UK offshore projects over the next three years, representing $22.6 billion in greenfield expenditure if UK prospective resources live up to expectations.

“If operators’ plans play out as intended, the 38 potential project commitments expected over the next three years will provide fertile ground for contractors, and a quick look at successful UK North Sea service companies from the recent past sheds some light on who may capture this growth in the near future,” says Audun Martinsen, head of oilfield services research at Rystad Energy.

TechnipFMC has been the top service provider in the UK market in recent years, measured in revenues, followed by Wood and Schlumberger.

With project sanctioning forecast to accelerate in the UK, Rystad Energy expects the EPCI market – engineering, procurement, construction and installation – to grow by 65% over the next three years, while the subsea and seismic markets are each forecast to expand by 35%. Maintenance & operations, well services & commodities, and drilling contractor purchases are each expected to grow at a more subdued rate.

“After several tough years, the sun may finally be ready to shine again on the UK offshore market,” Martinsen remarked on the opening day of Offshore Europe. Related: Busting The Myth Of The World’s Hottest Electric Car Market

UK offshore greenfield investments were severely hit during the downturn, declining from a peak of $20 billion in 2013 to a paltry $550 million in 2016, and in turn causing oilfield service unit prices in the region to fall by 27% on average.

Rystad Energy expects the number of UK project commitments to shrink slightly this year before rising sharply in 2020 and again in 2021, when we forecast a new peak with about 18 FIDs worth a combined $9.3 billion. We expect to see far fewer projects sanctioned in 2022 – only around seven – but they include some major developments and the collective capex commitment should still be large, projected at $8 billion.

“The largest single development on the list is Hurricane’s Lincoln project, at an estimated $5.4 billion, albeit recognizing that its schedule could be hindered depending on the viability of its fractured basement reservoir,” Martinsen remarked. “The largest project likely to be sanctioned before the end of this year is the $1 billion first phase of Siccar Point’s Cambo development.”

By Rystad Energy

More Top Reads From Oilprice.com:

https://oilprice.com/Energy/Crude-Oil/UK-Offshore-Oil-Gas-Is-About-To-Boom-Again.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNFX1xg6VWa-UyIrpC1e6zJa1dHm0

A growing role for electricity in Montney Shale natural gas development and exports, generated by British Columbia’s (BC) government-owned BC Hydro, will be promoted by federal, and power company planners in a new partnership.

Prime Minister Justin Trudeau and BC Premier John Horgan announced the creation of the Canada-BC Clean Power Planning Committee whose mandate emphasizes electricity as an environmental power source for natural gas activity.

Trudeau described the new planning partnership as “helping make the province a supplier of the cleanest natural gas in the world.”

Added Horgan, “We are taking an important step forward to build a more sustainable economy and protect our environment.”

The governments and BC Hydro plan to examine electrification projects worth an estimated C$680 million ($510 million), a list of which was not disclosed.

The provincial power company already has a role in northern shale production and liquefied natural gas (LNG) export development as a supplier for the Royal Dutch Shell plc-led LNG Canada export project now underway, along with the companion Coastal GasLink pipeline, which would move gas from the Montney region.

Construction also is underway for the C$10.7 billion ($8 billion) Peace River dam called Site C near the northern BC gas industry capital, Fort St. John.

Also in the Montney, BC Hydro recently completed a C$300 million ($225 million) transmission line and plans a second one for a forecast C$285 million ($213 million).

As the prime minister and premier made their announcement, prolonged native and environmental opposition escalated against northern industrialization with gas and electricity production and transmission.

Talks aimed at settling a protest lawsuit, against the Site C dam by West Moberly First Nations, broke down. A trial is scheduled for March 2022, when the project will still be under construction. The new reservoir would flood 55 square kilometers (22 square miles) of the Peace River Valley.

https://www.naturalgasintel.com/articles/119460-canada-bc-promote-electricity-in-powering-regions-natural-gas-activity&ct=ga&cd=CAIyHGY5ZDllMzk5NWUzYTU3MGU6Y28udWs6ZW46R0I&usg=AFQjCNG8TM34pbbqM_SjT_xXL2Px4OLEy

China aims to slash its growing dependence on gas imports by boosting domestic projects like shale fields as the security of its energy supply comes under the spotlight amid a festering trade war with the United States.

The row with Washington has overshadowed China’s economy, likely slowing gas demand growth considerably this year, a new government research report shows. But Beijing is funding new efforts to boost domestic production, particularly from so-called unconventional sources like shale gas, as weaning China off its import reliance takes on new importance.

The report, released on Saturday by the oil and gas department at the National Energy Administration (NEA) and a State Council research arm, calls for boosting natural gas production in key resource basins in the southwestern province of Sichuan, the Erdos basin in the north and offshore China.

According to the report, China’s gas consumption will rise by about 10% this year to 310 billion cubic meters (bcm), and to continue growing until 2050. Though slowing from last year’s 17.5%, 2019’s growth still represents an annual addition of 28 bcm, faster than the annual average growth of 19 bcm during 2007-2018, the report said.

While China imposed tariffs on imports of liquefied natural gas (LNG) from the United States starting last year, it remains the world’s second-largest buyer of the super-chilled fuel.

“China’s reliance oil and gas imports is growing too rapidly, with oil topping 70% and gas moving toward 50%,” said Lin Boqiang, Director of the Energy Economics Institute at Xiamen University.

The NEA report calls for building the Sichuan basin into the country’s top gas hub due to its rich resource base in both conventional gas fields and unconventional resources, such as shale gas and ‘tight gas’, a low-permeability gas derived from reservoir rocks and costly to develop.

“Through expanding development of deep-reservoir gas, tight gas and shale gas, Sichuan is likely to account for about a third of the country’s total natural gas output,” the report said, up from 20% currently.

Shale gas in Sichuan, the key region for China’s still fledgling shale gas development, could overtake conventional gas in output, the report added.

SHALE GAS

In a separate report carried by official news agency Xinhua on Saturday, Zhao Wenzhi, an influential researcher at China’s Academy of Engineering forecast that China’s shale gas output could reach 280 bcm, or 23% of the country’s total gas output, by 2035. Zhao also serves as president of Exploration and Production Institute at state giant PetroChina.

China last year produced about 10.9 bcm shale gas, less than 7% of the nation’s total gas output at 161 bcm.

The leap in projected shale gas output would require companies drilling over 500 wells a year between 2019 and 2035, double the 2018 level, Zhao was cited as saying.

Dominant state oil and gas firms have already ramped up drilling activities with near-record spending, in response to a call by President Xi Jinping in August last year to boost domestic energy security.

To expedite the growth, Beijing should consider offering tax sweeteners such as waiving resource tax on the shale gas, Zhao said.

China recently also announced a policy to extend subsidies for another three years on domestic production of unconventional gas, to include also tight gas for the first time.

In a research note last week, Wang Xueke, a consultant at Wood Mackenzie, raised China’s tight gas outlook to 85 bcm by 2040, up from an earlier forecast at 68 bcm.

Despite the lofty forecast and state subsidies, China faces complex geology and a lack of technological breakthroughs to make shale gas a profitable enough business to lure private money.

“The investment is still too small as only a handful state-run companies are exploring it ... Technology progress is not fast enough,” said Xiamen University’s Lin.

https://uk.reuters.com/article/us-china-energy-naturalgas/china-aims-to-rev-up-shale-gas-drive-wean-itself-off-imports-amid-u-s-trade-row-idUKKCN1VN0V6

U.S. oil and gas producer Concho Resources Inc said on Tuesday it would sell its New Mexico assets for $925 million to an affiliate of privately held Spur Energy Partners LLC, which is backed by global investment firm KKR.

Oil and gas companies have been looking to trim non-core assets and focus their spending on areas including Permian’s Delaware and Midland basins.

Concho, which has been hit by pricing concerns, took an impairment charge of $868 million on assets in the second quarter and said it did not plan to allocate capital on them for the next five years.

The sale includes a narrow strip of about 100,000 gross acres bordering its operations in the Delaware basin, which is spread across Texas and New Mexico.

The assets produce about 25,000 barrels of oil equivalent per day, the company said in a statement.

The proceeds from the deal will be used to pay down debt and initiate the share repurchase program of up to $1.5 billion.

Shares of Concho, which is the top oil producer in New Mexico, rose 1.2% to $74 per share in premarket trading.

https://www.reuters.com/article/us-concho-resources-divestiture/concho-resources-to-sell-new-mexico-assets-for-925-million-idUSKCN1VO1BB

U.S. exports of liquefied natural gas (LNG), negligible just three years ago, now amount to 10% of the global market and at 22 million tonnes so far this year are equal to the total volumes pumped out in 2018, Refinitiv data showed on Tuesday.

The data, comprised of tracked individual journeys made by LNG tankers from supply source to destination, also showed LNG production hit an all-time high last month of 31 million tonnes.

As global volumes grow, Qatar, for years the world’s largest LNG supplier, lost market share to Australia, which exported more LNG than any other country in the past two months.

The supply surge has been long in the making as liquefaction and export facilities on the U.S. Gulf Coast come onstream after years of development, boosted also by a new mega-terminal in Russia’s Arctic and facilities in Australia.

The batting order for the world’s largest exporters has been Australia, Qatar, the United States, Russia and Malaysia for the past two months, whereas in previous years Nigeria and Indonesia vied for places in the top five.

Soaring supplies from U.S. LNG terminals have upended the global market not just by boosting volumes - and depressing prices - but also through flexible destination contracts with long-term buyers. Such deals allow countries’ cargoes to ebb and flow as prices and demand dictate.

This is reflected in the data, which shows the influx of U.S. LNG to northwest Europe receded from a March peak while flows to Latin America picked up in periods of low hydropower.

Japanese and South Korean buyers, many of which supported U.S. projects at inception by committing to buy volumes, remained a strong albeit falling component of total sales.

But purchases by China stuttered to a halt in February as tariffs imposed on U.S. LNG by Beijing weighed on already poor pricing conditions for Asian buyers.

The U.S. supply surge has depressed global LNG prices, and with it, European benchmark gas prices, closing the arbitrage for cargoes between the Atlantic and Pacific basins. In addition, demand growth in Asia this year has been weak in the absence of extreme weather and in comparison to a strong 2018.

The LNG industry is set to continue its rapid development, taking advantage of the soaring energy needs of a richer developing world as well as demand for gas boosted by the fuel’s relatively clean environmental credentials.

In the United States, export plants with a capacity of 46 million tonnes per year (mtpa) are in operation or ramping up, with another 27 mtpa approved, financed and being built.

At such numbers, U.S. production will rival Qatar’s, although Doha plans to expand its own facilities to 110 mtpa.

New mega-projects with capacities of 10 mtpa or more and the expansion of existing facilities are planned in Mozambique, Nigeria, Arctic Russia, Canada’s West Coast, Mexico and Papua New Guinea.

https://www.reuters.com/article/us-usa-lng/u-s-lng-grabs-10-market-share-as-january-august-exports-equal-2018-volumes-idUSKCN1VO13W

In a regulatory filing, Schlumberger stated that as a result of the effects of current market valuations as well as various strategic decisions, the company expects that it will, during the third quarter of 2019, record material non-cash impairment charges relating to goodwill, intangible assets and fixed assets. "At the time of the filing of this Current Report on Form 8-K, Schlumberger is unable, in good faith, to make a determination of the amount or range of amounts of such impairment charges," the filing noted.

SLB Schlumberger $32.53 0.8 (2.52%) 06/27/19 GABE 06/27/19

http://thefly.com/permalinks/entry.php/id2958552/SLB-Schlumberger-sees-material-noncash-impairment-charges-in-Q&ct=ga&cd=CAIyGjBmYTQ4MmM0NmE3NmM1OTY6Y29tOmVuOkdC&usg=AFQjCNGDVTYqisZ_1StLnOSxPBEckQY6L

zoom Image courtesy of Novatek

Novatek, Russia’s natural gas producer and LNG major, has signed a heads of agreement on creating a joint venture with its compatriot shipper Sovcomflot.

According to the agreement, the parties intend to create a shipping company, with the potential involvement of other joint venture participants, Novatek’s statement reads.

The joint venture will focus on managing the construction and operations of Arctic ice-class LNG carriers ensuring the optimized transportation from Novatek’s future LNG projects in the Russian Arctic region, including the Arctic LNG 2 project.

“The efficient development of the Northern Sea Route as a viable, year-round navigational route requires consolidating experience in ice navigation, applying new technological solutions, and implementing the best international standards for navigational safety and training,” noted Novatek’s head Leonid Mikhelson.

“An optimized model of transporting LNG from the Russian Arctic region via the Northern Sea Route to major global markets, including the Asia-Pacific region, will support the successful implementation of Novatek’s Arctic LNG projects as well as reaching the goal set by the Russian President to ensure an increase in annual cargo traffic along the Northern Sea Route to 80 million tons in 2024,” Mikhelson said.

The heads of agreement to create a joint venture follows the strategic agreement signed in June last year on transporting LNG and condensate from the Arctic LNG projects.

http://bit.ly/2kqHdSL

India's H-Energy plans to import 2 million mt/year of LNG under new term contracts over a five-year period starting next year as it gets ready to capture a part of the growing gas market in India, its managing director and CEO Darshan Hiranandani told S&P Global Platts in an exclusive interview.

He said that the company would look at offers from all leading suppliers with the aim to receive the first delivery under those contracts some time in the third quarter or fourth quarter of 2020.

"Our team is working on the tendering process and it is getting ready. It will be for supplies on a five-year basis. We have an ecosystem of suppliers. We will move forward depending on what offers we will get," Hiranandani said.

H-Energy was established in 2009 and is currently developing LNG re-gasification terminals and cross-country pipelines on the west and east coast of India. H-Energy, through its marketing arm, is also offering end-to-end natural gas solutions, including LNG sourcing, re-gasification facilities and downstream deliveries.

India's share of gas in its overall energy mix is only 6%, much lower than the global average of more than 20%. New Delhi is stepping up efforts to raise the share of gas to 15% by 2030, but consumption growth faces hurdles because of infrastructural and pricing issues.

"We are hoping that gas will continue to increase its market share slowly but surely because the infrastructure for gas supply is improving across the board -- terminals, transmission pipelines and retail distribution," Hiranandani said. "The government's multi-pronged approach will help to push that growth."

"A lot of people think that a 6% share of gas in the energy mix is too little. I actually feel that with our limited infrastructure, it's actually a lot. I remain optimistic that as infrastructure grows LNG demand will continue to boom. I don't think the target of 15% is too ambitious."

He said that India's LNG demand could witness double-digit growth in some years and relatively lower growth in some years over the next five to 10 years.

"There won't be linear growth. It will depend on projects coming on stream. Some years it could be 5% growth and some years it could be 15%. But on an average we expect growth to be about 10% for the next five years."

According to S&P Global Platts Analytics, India's dependence on LNG imports is set to rise as domestic production is expected to grow at a compound annual growth rate of 8.89% over the next five years, while demand is expected to increase by a compound annual growth rate of 11.07% over the same period.

PROJECTS PROGRESSING WELL

Commenting on the various projects, Hiranandani said that the Jaigarh terminal in Rajasthan, which will have an estimated capacity of 4 million mt/year, would be ready for start-up by Q4 of 2019 instead of Q3, as initially planned, amid heavy monsoon rainfall.

"We have very little left to finish. Because of heavy monsoon rains, we had to let go of 60 days of productive work. We are hopeful that most of the work will be finished by the end of October and then commissioning should start. We expect the first delivery some time before the end of this year," he said.

H-Energy in January 2018 signed an agreement with "K" Line of Japan for the construction of an LNG terminal in West Bengal.

Hiranandani said that H-Energy had already received environmental clearance for the project. "We are hoping to start construction sometime in Q1 or Q2 of 2020 and hope to complete the project by the middle of 2022."

He said that the company was looking to set up breakbulk facilities -- which involves partial unloading of cargoesinto other ships -- at Kakinada in the southern state of Andhra Pradesh.

"Our break bulk facilities will be a game changer as it will give us the ability to re-load in smaller ships and supply to smaller customers directly. We see a lot of that happen in China and northern Europe," Hiranandani said.

Commenting on his vision for the company, Hiranandani said the company would remain focused on projects mainly in India and Bangladesh.

"Once we get Jaigarh fully operationalized and once construction starts in Kakinada and West Bengal, our business development teams can work further in terms of where we focus next -- midstream, downstream, or even possibly participating in the upstream," he said.

Commenting on the current state of the global market, Hiranandani said that market would continue to witness some oversupply as new projects come on stream. The oversupply comes at a time when global trade tensions and currency fluctuations are keeping the market on the edge.

"I think there are too many variables for the market now for people to figure out what's happening. But I feel that the gas market is fairly inelastic for most markets. Europe, Asia and the US will have to go back and start buying for the winter," he added.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/090219-india-ceo-series-robust-demand-outlook-whets-h-energys-appetite-for-lng-term-deals?utm_source=hootsuite&utm_medium=twitter&utm_term=plattsoil&utm_content=0dad44d4-b819-477a-986e-f612627967cf&utm_campaign=lngnews

Novatek eyes India’s LNG market with H-Energy MoU

zoomImage courtesy of Novatek

Russia’s largest independent natural gas producer has signed an LNG cooperation memorandum of understanding with India’s H-Energy Global.

The MOU envisages cooperation in LNG supplies to India on a long-term basis, joint investment in future LNG terminals of H-Energy and LNG projects of Novatek, as well as establishing a joint venture to market LNG and natural gas from Novatek’s portfolio to end-customers in India, Bangladesh and other markets, the company’s statement reads.

“India is one of the largest and fastest-growing LNG markets, and will be one of the main sources of future growth in global demand for natural gas,” Novatek’s head, Leonid Mikhelson, said.

“The Memorandum of Understanding is an important step towards entering the end-customer market in India, which is of great interest to Novatek taking

into account our strategic plans to implement new LNG projects and significantly increase our LNG production volumes,” he added.

Novatek operates the Yamal LNG project that has three liquefaction trains in operation at Yamal LNG with cumulative nameplate production capacity of 16.5 million tons per annum.

Novatek is also building the fourth liquefaction train of 900,000 tons per annum utilizing the hydrocarbon resources of the South-Tambeyskoye field in the Russian Arctic.

The company is also developing its second liquefied natural gas export project, named the Arctic LNG 2, that envisages constructing three LNG trains at 6.6 million tons per annum each, using gravity-based structure (GBS) platforms. The project is based on the hydrocarbon resources of the Utrenneye field.

https://www.lngworldnews.com/novatek-eyes-indias-lng-market-with-h-energy-mou/

Natural gas prices in Europe are set to fall further below their lowest in a decade as suppliers show few signs of scaling back abundant deliveries.

Inventories are near capacity weeks earlier than usual and are being flooded with more fuel coming both from tankers and pipelines. While producers have reduced some flows with repairs and maintenance at gas fields and processing plants, the benchmark price for gas in the Netherlands is struggling to recover from a crash below 10 euros ($11) a megawatt-hour earlier this summer.

“In September, gas storage sites in northern Europe will be full, increasing the risk of a further downside in prices,” said Niek van Kouteren, a senior trader at PZEM, a Dutch energy company. “Under a certain price, producers would be forced to extract less gas. But at the same time, big suppliers such as Russia” are trying to increase market share.

The only way for European prices to recover would be to scale back flows from Russia or Norway or halt more arrivals of cargoes liquefied natural gas, said Norbert Ruecker, head of economics at Julius Baer Group Ltd.

Dutch month-ahead prices may drop another 20% in the autumn, he said. “If things turn out really bad, maybe the bear case is even lower.”

Russian energy giant Gazprom PJSC said last week that its exports to Europe will decline to 192 billion cubic meters this year, 4.5% lower than the record-high volumes in 2018. Its average gas price is also expected to fall 13% in comparison what it recorded last year.

Nevertheless, Gazprom looks unlikely to turn off the taps just because of low prices.

“When we have an opportunity, we make extra sales,” Mikhail Malgin, deputy department head at Gazprom Export, said on a conference call with analysts last week. “The market share per se is not our goal but rather a consequence of our actions”

While injections into storage sites have now slowed amid Norwegian maintenance and lower LNG receipts, reducing the probability that storage capacity is breached and the risk of a “full price capitulation,” continued stockpiling through October will keep prices under pressure until the winter season, Goldman Sachs Group Inc. said in a report Monday.

Prices would have to fall much further for producers to make significant output cuts, according to Ahmed Hammoudan, a senior gas trader at Dutch energy company Eneco.

“Big suppliers are not driven by price, but by revenue,” Hammoudan said. “Even if prices collapse, they might not be under pressure to reduce flows as they hedge operations. And these companies want to deliver volumes.”

https://www.worldoil.com/news/2019/9/3/natural-gas-glut-grows-in-europe-as-prices-hit-10-year-low

Royal Dutch Shell, one of the world’s largest liquefied natural gas (LNG) suppliers, has asked U.S. regulators to extend the time by which it should complete an LNG export project in Louisiana by five years to 2025, regulatory filings showed.

The project, a 50-50 venture with U.S. midstream company Energy Transfer, envisaged converting an existing import and regasification facility in Lake Charles into a multi-train, 16.45 million tonnes per year (mtpa) facility.

The delay takes a major U.S. export project out of the race to achieve a final investment decision (FID) in time to start operations during an anticipated supply downturn in 2023-2024.

About a dozen projects in North America, mostly in the Gulf of Mexico, are vying for FID this year or early next year to start production in time to hit that sweetspot. But the more get approved, the less likely other projects are to go ahead as the expected dearth turns into oversupply.

The delay is due to Shell’s takeover of the project after its $53 billion acquisition of BG Group in 2016 prompted it to re-evaluate and strike new agreements, the Anglo-Dutch company said in a letter dated last Friday to the Federal Energy Regulatory Commission.

It said following this process, the project plans had not changed but a new 50-50 ownership structure with Energy Transfer had been struck and Shell had committed to taking 50% of the export capacity.

“Under the new Project Framework Agreement, ET and Shell have established a detailed process for the development of the Project which includes milestones that are expected to result in the Project sponsors reaching FID as early as the end of 2020,” it said in the letter.

“Completion of construction of the LNG export terminal facility is expected to occur as early as the second half of 2025.”

https://uk.investing.com/commodities/real-time-futures

The $21 billion Arctic liquefied natural gas (LNG)-2 project in Russia received the green light on Thursday after project participants signed a final investment decision at an economic forum in Vladivostok.

The project, led by Russia’s biggest private gas producer Novatek, includes French energy producer Total, China’s National Petroleum Corp [CNPET.UL], CNOOC and the Japan Arctic LNG consortium. The Japanese consortium comprises Mitsui & Co and state-owned JOGMEC - formally known as Japan Oil, Gas and Metals National Corp.

“This is an important project for Russia and follows our strategy to create capacities for LNG production,” Russian Energy Minister Alexander Novak said, adding that investments in the project had been set at $21 billion.

Arctic LNG 2 will be the third LNG project for Novatek, which hopes to match Qatar in production of the super-chilled fuel.

Japanese Industry Minister Hiroshige Seko said the project is one of the largest in the history of Japanese-Russian relations.

“It will unite Japan and Russia even more, as well as Europe and Asia. The Japanese government will provide all necessary assistance for the realization of this project,” he said.

The Arctic LNG 2 project will include construction of three LNG trains with a capacity of 6.6 million tonnes per annum (mtpa) of LNG each and at least 1.6 mtpa of gas condensate, according to Novatek’s website.

https://www.reuters.com/article/us-russia-energy-novatek-lng/russias-21-billion-arctic-lng-2-project-gets-green-light-idUSKCN1VQ0IH

Offshore drilling contractor Northern Offshore has received a firm letter of award for the currently stacked jack-up drilling unit Energy Emerger for work offshore Abu Dhabi in the United Arab Emirates.

The term of the award is for four years, Northern Offshore said in a statement on Wednesday.

The Energy Emerger is a GustoMSC CJ46-X100-D jack-up that was delivered to Northern Offshore in December 2017 and is currently warm stacked at the Shanghai Waigaoqiao Shipyard in Shanghai, China.

The rig will drill high-pressure and high-temperature wells and is expected to start operations during the first quarter of 2020, the rig owner said.

Chairman and CEO, Dr. Yuanhui Sun, stated: “We are very pleased to have added an additional rig into the Middle East region with a long-term contract for the Energy Emerger. We are also pleased to have earned the trust of our new customer in the Arabian Gulf and look forward to creating a long-term and mutually-beneficial relationship with them.”

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Japan’s Saibu Gas has become the new partner of the Russian LNG project operator Novatek following a heads of agreement signed on Thursday.

According to the agreement, the parties intend to establish a joint venture focused on marketing LNG and natural gas to end customers and developing the business for bunkering and gas-fired power generation in Japan and the Asian region.

Novatek said in a statement that the parties are also looking to partner up on constructing and operating a new LNG storage tank at the Hibiki LNG terminal.

“We have made another important step forward in implementing our strategy to enter the end customer market in key gas consuming countries, among which Japan is one the biggest markets and long-time consumer of LNG,” noted Novatek’s head Leonid Mikhelson.

“The creation of our joint venture with Saibu Gas allows us to increase the marketing flexibility of natural gas supplies and create additional opportunities for LNG sales in this important gas consuming region,” he concluded.

http://bit.ly/2kw8m6T

Argentina pursues $5 billion LNG project amid political havoc

By Jonathan Gilbert on 9/4/2019

BUENOS AIRES (Bloomberg) - Argentina’s state-run oil company, YPF SA, is pushing ahead with plans to build a $5 billion natural gas export terminal despite the political and financial chaos racking the nation.

The driller, which has led development of the nation’s Vaca Muerta shale trove, is in talks with potential international and domestic partners over designs for a liquefied natural gas facility. But the backdrop for those discussions has shifted dramatically after opposition candidate Alberto Fernandez beat market-friendly President Mauricio Macri in a key primary vote last month, sending shares of Argentine companies tumbling on concerns that a more protectionist government will take power.

YPF executives, however, remain bullish about Argentina’s chances of becoming an established member of the small but growing club of LNG-exporting countries. “We can’t put the cart before the horse by distracting ourselves with current events,” said Marcos Browne, YPF’s executive vice president for natural gas and power. “This is the direction we need to move in.”

Argentina faces stiff competition for LNG buyers as suppliers from the U.S. to Australia increase exports, adding to a global glut and sending prices for the fuel tumbling. But the YPF terminal could benefit from its location in the southern hemisphere, where seasonal gas use ebbs when it’s coldest in Asia and Europe, boosting heating demand in those regions.

The Tango floating LNG facility, which chills gas into liquid for shipment overseas, has been ramping up production on Argentina’s Atlantic coast as it readies the nation’s first full cargo of the fuel, to sail at the end of October. Tankers will leave the Bahia Blanca port every 40 days or so until May 2020, when Argentina’s winter starts and domestic gas demand surges. Exports will resume this time next year.

But the barge can only produce 500,000 metric tons a year of LNG, compared with global trade of about 290 million metric tons in 2017. A larger terminal that gives Argentina access to big importers in Asia is key to unlocking production in Vaca Muerta, where drillers face poor demand for much of the year.

Energy Turnaround

It’s still unclear whether the LNG facility would be onshore or offshore, and where it would be built. Options include anchoring several floating liquefaction units like the Tango in a row, similar to Golar LNG’s project in Cameroon, Browne said.

At YPF, a new government will likely mean management changes, and it’s unclear what the political situation will look like when final plans for the terminal are ready in about two years. But Fernandez is expected to keep supporting development of shale fields because Argentina desperately needs export dollars to shore up its currency, the peso.

“The LNG terminal will be a machine for bringing in dollars,” said Sebastian Mocorrea, YPF’s executive vice president for corporate affairs. “Nobody in their right mind would meddle with it.”

Related News ///

FROM THE ARCHIVE ///

http://ow.ly/wy7t50vWJSp

Equinor has, on behalf of the partners of the Northern Lights project, signed memoranda of understanding with seven European companies to develop value chains in carbon capture and storage.

Equinor, in cooperation with its partners Shell and Total, is studying the possibilities for developing a CO₂ storage on the Norwegian continental shelf (NCS), the Norwegian company said on Thursday.

The Northern Lights project includes transport, reception, and permanent storage of CO₂ in a reservoir in the northern part of the North Sea. The storage project is part of the Norwegian State’s demonstration project “Full-scale CO₂ handling chain in Norway.”

Memoranda of understanding have been signed with Air Liquide, Arcelor Mittal, Ervia, Fortum Oyj, HeidelbergCement AG, Preem, and Stockholm Exergi. According to the agreements, the parties will cooperate on possible CO₂ handling at relevant third-party’s premises and on transport to the Northern Lights project.

The memoranda of understanding imply that the parties will evaluate solutions for CO₂ deliveries and transport; develop a timeline for possible final investment decision and start of operations, and cooperate on the CCS dialogue with national authorities and the EU.

“Carbon capture and storage will be vital to reach the global climate goals of the Paris Agreement. Sustainable carbon capture and storage projects can only be developed in cooperation between governments and companies. We are therefore very pleased that the Northern Lights partners and leading European companies are taking the first steps to realize a European CO₂ transport and storage system,” said Eldar Sætre, president and CEO of Equinor.

Equinor said that the final binding commercial agreements will depend on positive investment decisions for the Northern Lights project, the Norwegian State’s full-scale carbon capture and storage project and for third-party projects.

The partners are currently reducing costs and further developing the Northern Lights project aiming for an investment decision in 2020.

“We are also cooperating with the authorities to establish a commercial framework enabling us to pursue the project,” said Sverre Overå, project director for the Northern Lights project.

More than 150 people from Equinor, Total, and Shell are currently involved in the Northern Lights project. At the end of 2019, the partnership plans to drill a confirmation well for CO₂ storage in the Johansen formation covered by the Aurora license (EL001) to study the reservoir’s suitability and capacity for CO₂ storage. Earlier this year the authorities decided to help fund the work on this well.



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Pioneer Natural Resources Company (PXD - Free Report) recently showcased its Permian Basin strength at the Barclays CEO Energy-Power Conference 2019, held in New York. The CEO of the company, Scott Sheffield said that the company has roughly 10 more years of drilling inventory in the region, where it can keep producing without a deceleration in the current output pace. Moreover, given its acreages in the prolific basin, the company does not have to turn to less productive sites.

Unlike many other operators in the Permian Basin, Pioneer steered clear of downspacing issues, primarily due to the amount of choice acreage it has in the region. Downspacing is the method of drilling wells closer together in a particular area to maximize output. The pure-play Permian basin producer has operations across 680,000 net acres in the Midland Basin. While its peers have well spacing of less than or equal to 600 feet, Pioneer’s wells are situated 850 feet away from each other.

https://www.zacks.com/stock/news/503283/pioneer-pxd-can-drill-its-best-inventory-for-another-decade&ct=ga&cd=CAIyGmIyMzkzNGFiNzQ2ZGQyMWQ6Y29tOmVuOkdC&usg=AFQjCNFW26l_Oiq7zuiMuqTFoRIxwsvdK

Equinor launches $5 billion share buy-back program

9/5/2019

OSLO - Equinor is launching a share buy-back program of up to $5 billion over a period until the end of 2022. The first tranche of the program of around $1.5 billion is commencing today and will end no later than 25 February 2020.

“Equinor is committed to capital distribution to our shareholders. We have over the last years built a strong financial position with solid credit ratings and a net debt ratio around 20%. The upcoming start-up of the world-class Johan Sverdrup field, combined with several other new fields in production, provides additional confidence in our outlook for production growth and increased cash generation capacity. We are therefore in a good position to increase capital distribution, while continuing to invest in our high-quality project portfolio”, says Eldar Sætre, president and CEO of Equinor ASA.

“Following strong operational improvements over recent years, we increased the quarterly dividends by 13% this year. Utilizing share buy-backs as an additional tool to strengthen capital distribution is aligned with our dividend policy”, says Equinor’s chief financial officer, Lars Christian Bacher.

The share buy-back program of up to $5 billion, including shares to be redeemed from the Norwegian State, is intended to be executed in the market until the end of 2022. Based on the closing Equinor share price and the USD/NOK exchange rate on 4 September 2019 the full program represents around 292 million shares or around 8.7 % of the share capital. The purpose of the share buy-back program is to reduce the issued share capital of the company. All shares repurchased as part of the program will be cancelled.

According to an agreement between Equinor and the Norwegian State, represented by the Ministry of Petroleum and Energy, the Norwegian State will participate in share buy-backs on a proportionate basis, ensuring that its ownership interest in Equinor remains unchanged at 67%.

The share buy-back program will be structured into tranches where Equinor will buy back a certain USD value of shares over a certain period. For the first tranche, running from 5 September 2019 up to no later than 25 February 2020, Equinor is entering into a non-discretionary agreement with a third party who will make its trading decisions independently of the company. In this first tranche, shares for up to USD 500 million will be purchased in the market, implying a total first tranche of around USD 1.5 billion including redemption of shares from the Norwegian State.

The execution of further tranches of the program will be notified to the market and is conditional upon future annual general meetings renewing the authorization to buy back own shares and renewal of the agreement with the Norwegian State. Future tranches are also subject to commodity price conditions and balance sheet strength.

As described in the dividend policy, it is Equinor’s ambition to grow its annual cash dividend, measured in USD per share, in line with long term underlying earnings growth. In addition to cash dividend, the dividend policy outlines that Equinor might buy back shares as part of total distribution of capital to shareholders.

Related News ///

FROM THE ARCHIVE ///

http://ow.ly/pMUZ50vXvqE

The Freeport liquefied natural gas (LNG) project in the United States has shipped its first commissioning cargo, adding to the glut of supply of the super-chilled fuel globally.

The company said in a statement late on Tuesday that it has shipped its first LNG commissioning cargo for Train 1 from its liquefaction facility located on Quintana Island in Freeport, Texas.

About 150,000 cubic meters of LNG was loaded on board the LNG tanker LNG Jurojin, which left the Freeport LNG terminal on Sept. 3, the company said.

The tanker is currently bound for Jebel Ali, in the United Arab Emirates, according to shiptracking data on Refinitiv Eikon.

“This first cargo loading ... gets us one step closer toward our start of commercial operations which is anticipated later this month,” said Michael Smith, chairman and chief executive of Freeport LNG.

The start-up of Freeport LNG is expected to add to a supply glut which has been weighing on spot LNG prices in Asia.

“The start-up of Freeport LNG contributes to even more supply growth at a time when the market is already oversupplied,” said Edmund Siau, an LNG analyst with FGE.

“Winter is just around the corner and seasonal demand will help to absorb this new supply, however we see a key risk posed by European gas inventories that are already above 90% full.”

Japan’s Osaka Gas Co Ltd and JERA Co, a joint venture between Tokyo Electric Power Co and Chubu Electric Power Co, will each lift half of Train 1’s total contracted capacity of about 4.64 million tonnes per annum (mtpa) once commercial production starts.

Freeport has about 20-year liquefaction tolling agreements with Osaka Gas and JERA from Train 1. Under the deal, both companies will secure LNG without destination restrictions, helping them diversify supply sources and price indices, as well as enhance procurement stability and flexibility.

https://www.reuters.com/article/us-usa-lng-freeport/freeport-lng-ships-first-commissioning-cargo-from-texas-plant-idUSKCN1VP0BH

Exxon Mobil (XOM.N) has agreed to sell its Norwegian oil and gas assets for up to $4 billion, marking the U.S. firm’s exit from production in the country after more than a century, three sources familiar with the matter said on Thursday.

Exxon said in June it was looking to sell its Norwegian upstream portfolio, which comprises minority stakes in more than 20 fields, operated by local producer Equinor (EQNR.OL) and Anglo-Dutch oil major Royal Dutch Shell (RDSa.L).

An Exxon spokeswoman said: “As a matter of practice, we don’t comment on commercial discussions.”

Shares in Exxon, the world’s biggest publicly traded oil company, rose 1.7% to a session high in New York after Reuters reported a sale had been agreed.

The Irving, Texas-based company has held talks in recent weeks with a number of interested parties including Oslo-listed companies Equinor, Aker BP (AKERBP.OL), and DNO (DNO.OL), Stockholm-listed Lundin Petroleum (LUPE.ST) as well as Var Energi, backed by Italy’s Eni (ENI.MI), and private equity firm Hitech Vision, industry sources said.

The three sources said that Exxon had closed the sale process in recent days with one buyer after agreeing on the terms of a sale.

Exxon hired investment bank Jefferies to run the sale process, banking sources told Reuters last month.

Jefferies declined to comment.

In 2017, Exxon’s net production from fields off Norway was around 170,000 barrels of oil equivalent per day, according to its website.

The sale, if approved by regulators and completed, comes after Exxon focused in recent years on growing its onshore U.S. shale production, particularly in the Permian basin, as well as developing huge oil discoveries in Guyana.

Exxon is also considering selling its assets in the British North Sea after more than 50 years, industry sources told Reuters last month.

https://www.reuters.com/article/us-exxon-mobil-m-a-norway-exclusive/exclusive-exxon-agrees-4-billion-sale-of-norway-oil-and-gas-assets-sources-idUSKCN1VQ23W