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Global floating storage overhang cut to 8-month low

The overhang of oil stored at sea compared to previous-year levels has dropped to just 20pc of what it was during its peak in May, as cheaper on-land storage becomes available and port congestion in China continues to steadily clear.

The volume of oil being stored on tankers for at least seven days has fallen to 201mn bl, just 50mn bl above last year's figure on the same date and its lowest level since 6 April. Floating oil storage's most recent peak was 14 May, 374mn bl, which was 249mn bl above the 14 May 2019 figure, according to Vortexa.
Even though a new wave of Covid-19 cases is stalling the oil demand recovery, with trading firm Trafigura slashing its global oil demand projection by 2.5mn b/d, crude production cuts from Opec+ appear to be preventing the type of brimming land-based storage that spurred oil traders to look to the more costly storage option of oil tankers earlier this year.
Traders are opting to use the tankers already booked on such charters for standard voyages instead of storage.
The number of tankers booked on short-term time charters that are actually in floating storage has fallen to 36 compared to its peak of 78 on 14 July, according to the Argus floating storage bookings database. Most of the around 300 tankers currently employed on short-term time charters are back in the spot chartering market or are transporting cargoes for the time charterer.
Another factor dropping stored-at-sea oil volumes is the steady clearing of port congestion in China. The number of very large crude carriers (VLCCs) waiting to discharge crude in China has fallen to 20, compared to 31 in July, according to Vortexa, as the pace of Chinese chartering slowed after the frenzy that saw Chinese traders capitalize on low crude prices in April.
Floating storage resurgence unlikely
Energy traders are largely staying away from the short-term time chartering market despite depressed rates, suggesting a floating storage rebound is not imminent. Traders have booked only five VLCCs, the Ellinis, Hunter Idun, Nissos Kythnos, DHT Redwood, and Desh Ujaala on short-term time charters since the beginning of October at an average rate of $29,000/d.
The new short-term charters do not necessarily represent an increase in floating storage demand, but in some cases act as extensions of previous floating storage-eligible charters. For example, last month's one-year charter to Unipec of the Nissos Kythnos VLCC comes immediately after the conclusion of the ship's previous short-term time charter at $85,000/d, also to Unipec.
Further dampening the prospects for a rebound in floating storage charters is Opec+ countries' willingness to extend crude production cuts in January of next year. Such a production cut extension "could be envisaged" for the first half of 2021 if demand continues to lag, said Opec president Abdelmadjid Attar.
It was the Saudi-Russia crude price war combined with uncertain oil demand because of the Covid-19 pandemic that caused floating storage to surge in April.
Source: Argus
Venezuela oil exports fall to new low in October as clients walk away

Venezuela’s oil exports fell to a historic low of 359,000 barrels per day (bpd) in October as most of state-run PDVSA’s long-term clients paused trade to meet a U.S. deadline to halt business with the firm, according to data seen by Reuters on Monday.

The United States set an October-November deadline for PDVSA’s long-term customers – including Italy Eni ENI.MI, Spain’s Repsol REP.MC and India’s Reliance Industries RELI.NS – to stop oil swaps it had authorized this year as exceptions to sanctions on Venezuela.
None of those companies loaded cargoes of Venezuelan crude in October, shrinking PDVSA’s portfolio of customers, according to internal documents from the state company seen by Reuters as well as Refinitiv Eikon vessel tracking data.
Thailand’s Tipco Asphalt TASCO.BK took a cargo of Venezuela’s crude on the tanker Explorer and it has at least two more cargoes about to depart in November before winding down trade with PDVSA, according to the data.
A total of 26 vessels set sail from the sanctioned nation last month. The 359,000 bpd they exported is the lowest monthly average since early 1943, according to figures from Venezuela’s oil ministry.
PDVSA and its joint ventures exported 381,000 bpd in June and 388,000 bpd in July, but shipments had bounced to 440,000 bpd in August and 703,000 bpd in September, helped by last-minute purchases by their traditional customers, according to the internal PDVSA documents and Eikon data.
PDVSA did not immediately reply to a request for comment.
The main destination for Venezuela’s oil in October was Asia, with about one third of total exports, followed by Cuba with some 104,000 bpd.
Venezuela’s exports are increasingly difficult to track since a growing portion of oil shipments originates in ship-to-ship operations, not at PDVSA’s ports.
In October, PDVSA inaugurated a new spot for transferring crude between tankers near La Borracha island off the nation’s eastern coast.
Source: Hellenic Shipping
China may award up to 243 mil mt crude import quotas for qualified refineries in 2021

China’s Ministry of Commerce said Nov. 2 that qualified refineries and trading companies will be able to apply for up to 243 million mt (4.86 million b/d) of crude oil import quotas for 2021 by Nov. 15.

The 2021 import quota ceiling volume of 243 million mt is 41 million mt, or 20.3%, higher than the 202 million mt set for 2020 and 2019, according to S&P Global Platts calculations based on ministry statements.
Refinery sources said the incremental volume of 41 million mt should cover the feedstock requirements for the new 20 million mt/year phase 2 project of the Zhejiang Petroleum & Chemical in Zhejiang province, as well as the need of the new 16 million mt/year Shenghong Petrochemical in Jiangsu province, both in eastern China.
The Phase 2 of the ZPC project aims to start up by end 2020, while Shenghong Petrochemical is slated to come on stream by end-2021.
In addition, the ceiling volume could also include those for trading companies that have been approved with an import license, according to trading sources.
Xiamen Tongxin Trading Company, Xiamen Xiangyu Logistic Group, Fujian Minhai Energy International Trading Company, were awarded import licenses by the ministry in mid-2020.
2020 update
So far in 2020, the ministry has allocated a total 184.55 million mt of quotas to trading companies and refiners. Of this, 179.4 million mt was allocated to 44 qualified independent refineries, making up more than 97% of the total quota permit to non state-run companies.
The ministry might increase quotas if oil companies need to import more crude based on their increased capacity. The ministry will also allow quota holders to make downward adjustments, in which case the remaining quotas will be returned to the ministry by Sept. 1 during the corresponding year.
The first batch of quotas for 2021 will be awarded by Dec. 31, 2020, and the rest will be allocated in the following months, depending on market conditions.
However, the ministry will not allocate 2021 crude import quotas to those who have not imported crude over the past two years, according to the ministry statement released Nov. 2.
In China, refineries built and operated by state-owned companies — Sinopec, PetroChina, CNOOC and Sinochem — do not need quotas to import crude oil.
However, all other refineries, including independent ones and those owned and operated by state-owned companies like ChemChina and Norinco, require quotas to crack imported crude oil.
Source: Hellenic Shipping
LNG tankers without reservations seeing longer waiting times at Panama Canal

The Panama Canal Authority has raised daily transits to ease wait times of up to more than a week for LNG tankers currently passing through without a reservation.

The delays observed in recent days for a small portion of vessels transiting the shortest route from the US Gulf Coast to East Asia are due to fog, higher-than-average arrivals and additional safety procedures to prevent further spread of the coronavirus, the canal operator told S&P Global Platts Oct. 29.
Market participants have reported wait times recently of six to eight days for northbound transits and four to six days for southbound transits. Across the month of October, the average transit time is 71 hours – slightly faster than last year — with some vessels making the journey through the Panama Canal in under 20 hours, Platts Analytics data showed.
The delays for some vessels come during a particularly bullish period for US LNG exporters.
Utilization at the six major US liquefactions terminals on the Gulf and Atlantic coasts rose Oct. 29 to a record 9.645 Bcf/d, slightly above the previous record of 9.629 Bcf/d set on March 31 before the worst of the market impacts from the pandemic set in. The Platts JKM, the benchmark price for spot-traded LNG delivered to Northeast Asia, has jumped almost fourfold from its historic low at $1.825/MMBtu on April 28, to $7.176/MMBtu on Oct. 29.
While some buyers of US LNG in the spring, when prices were low, slow steamed Gulf Coast shipments to East Asia by heading eastward toward Europe and Africa, the much higher end-user prices now in Asia make shorter voyages westward more preferable, especially with the Atlantic tanker day rate at $120,000, almost double the rate of $62,000 at the beginning of October.
In a statement to Platts, the Panama Canal Authority acknowledged the extended waiting time for vessels that have been arriving at the transit zone without a reservation in recent days. In response, the Canal Authority said it has adjusted its operations to raise daily transits to 37, reducing the backlog while maintaining the safety measures that have allowed the waterway to remain open without any pause in transits.
Source: Hellenic Shipping
New Covid lockdowns to hit oil demand: Trafigura, Vitol

Renewed lockdowns in Europe and rising Covid-19 infections in the US could slash oil demand by up to 2.5mn b/d from previous projections, although much of the impact may already be reflected in crude prices, top executives at global trading firms Trafigura and Vitol said.

A second wave of coronavirus infections will lead to further demand destruction, Trafigura's chief executive Jeremy Weir said at the FT Commodities Asia Summit today.
"We're possibly talking another 1mn b/d in the US, probably 1.5mn b/d in Europe. It's not looking good for the foreseeable future," Weir said.
Trafigura had been projecting global demand at around 92mn b/d, but this could now slip to around 88mn-89mn b/d in the short term, he said.
Vitol is "a little bit more optimistic" but still sees a 500,000 b/d demand loss across northwest Europe because of the latest lockdowns, the company's chief executive Russell Hardy said.
"Nothing we have seen over the last couple of weeks should be a shock to anyone. A second wave was expected," he said.
Vitol sees demand averaging around 96mn b/d over the northern hemisphere winter period, about 6mn b/d lower than a year earlier. "The majority of that [demand loss] is aviation, but there's a chunk of gasoline and diesel, especially post the recent lockdowns," he said.
Supply tightness is supporting crude markets. Cuts by the Opec+ group and other producers including the US have removed around 6mn-7mn b/d from the market, which is more than covering the demand drop, Hardy said.
Markets are still drawing down the 1bn-1.2bn bl of stocks that were built up in the second quarter, at a pace of around 2mn b/d, Hardy said. "We mustn't lose sight of that fact — albeit we are in the middle of a crisis of crisis of confidence at the moment, so the market reaction is not at all surprising."
Market participants may be looking for a rollover of Opec+ production levels, Hardy suggested. "I don't think there's a need for further cuts but kicking the increase into the long grass would probably be welcomed by the market." The 2mn b/d increase that has been mooted for 1 January would be the difference between a continued stockdraw and a larger stockbuild through the first quarter of 2021, he said.
Oil prices are already largely reflecting the latest bad news on demand, Weir said, noting the 3-4pc drops in Brent and WTI crude prices in Asian trading today. Uncertainty over this week's US election or another geopolitical shock could send prices slightly lower.
"But we are at distressed levels now, let's face it. These numbers are not good, and you are probably likely to see further cutbacks of production levels" as a result, Weir said.
Source: Argus
China ZPC starts trial runs at 400,000 b/d expansion

Chinese private-sector firm Rongsheng has started trial runs at a 400,000 b/d expansion of its ZPC refinery in Zhejiang, which will take total capacity to 800,000 b/d.

Rongsheng held a ceremony to mark the start of the refinery's second phase yesterday. ZPC will add two 200,000 b/d crude distillation units (CDUs) in the second phase expansion, the second of which is scheduled to start trial runs in 2021.
The second-phase units are designed to produce 88,000 b/d of gasoline, 32,000 b/d of diesel and 63,000 b/d of jet fuel. The complex is geared towards producing feedstocks for Rongsheng's petrochemical operations.
ZPC was awarded a 400,000 b/d non-state crude import quota for 2020, enough to cover the nameplate capacity of its first phase. The Chinese government today issued a total of 4.88mn b/d of non-state crude import quotas for 2021, up by 21pc from this year, although a company breakdown is yet to be announced.
Rongsheng in October purchased about 10mn bl of Mideast Gulf crude for loading and arrival across December and January, ahead of the second-phase start-up.
ZPC is based on Yushan island, one of multiple islands in the emerging oil hub of Zhoushan on China's east coast. It operates a 300,000t crude terminal on Waidiao Island and the 800,000 b/d Waidiao-Mamu-Yushan crude pipeline. Another new 300,000t crude terminal is operational on Huangzeshan island, while ZPC is also planning an additional 800,000 b/d undersea crude pipeline connecting Huangzeshan and Yushan island.
ZPC operates 3mn m³ of crude storage at Mamu and 1.6mn m³ on Yushan island, as well as 1.9mn m³ of operational storage for products. It is adding another 1mn m³ of oil and chemical product storage capacity for the second-phase expansion.
The company is planning to build more facilities on nearby Jintang island, including several crude terminals and 8.5mn m³ of crude storage, over the next five years.
Source: Argus
Oil demand hit may be hundreds of thousands b/d from Europe lockdowns

Oil demand may drop by “hundreds of thousands” of barrels per day from lockdowns called in recent days in Western Europe including Germany, France and England, Vitol’s Asia head Mike Muller said Nov. 1.

“I do think the impact in Western Europe is going to be hundreds of thousands of barrels a day but we need to decide how many hundreds of thousands,” Muller told a Gulf Intelligence webinar.
As for crude prices on Nov. 2, following the weekend announcement of England’s lockdown, he said: “We’re not going to see a violent reaction downwards in price on Monday because I think the market could see this coming Wednesday, Thursday, Friday already.”
Oil analysts are rethinking demand estimates with a view toward live traffic data and mobility restrictions because of the new lockdowns, Muller said.
“The dust hasn’t settled on that because people are throwing all sorts of numbers around,” he said.
One estimate that demand could fall by 1.7 million b/d in Germany and France alone is “completely overblown,” he added.
England will go into lockdown on Nov. 5, except for schools and construction, and remain in place until Dec. 2, UK Prime Minister Boris Johnson said Oct. 31.
France, Germany and Belgium have also imposed travel restrictions in an attempt to curb a second COVID-19 wave.
Many nations had imposed lockdowns in the first COVID-19 wave, which sent Dated Brent to as low as $13.24/b in April. As a result, the 23-country OPEC+ alliance agreed to rein in nearly 10% of global crude supply, a critical step in clawing back oil prices.
S&P Global Platts assessed Dated Brent at $36.205/b on Oct. 30, down from a nearly 6-month peak of $45.985 on Aug. 25.
Source: Hellenic Shipping
Oct throughput falls as state-owned refiners cut runs to 79%

Crude throughputs at China’s refineries extended the falling trend in October, with both state-owned oil companies and independent refineries cutting run rates amid weakening refining margins.

Combined run rates at the four state-owned oil companies — Sinopec, PetroChina, CNOOC and Sinochem — averaged 78.9% in October, down from 81.5% in September, data collected by S&P Global Platts showed on Oct. 28.
It was the fourth monthly consecutive drop since July, when it was 83.1%, a six-month high, Platts data showed.
Sinopec, the world’s biggest refiner by capacity, led the cut in October with five percentage point reduction to 82% from September, compared with 88% in October 2019.
The company had planned to lift its throughput by 4.3% year on year and process 130 million mt of crude oil in the second half of this year. Q4 is usually a busy season for refineries to hit annual targets.
“But it is impossible for us to meet the target this year any way. All we think about is to lower refining loss in the rest of the year,” a Sinopec refiner told Platts.
“Domestic demand is not strong while oil product prices in overseas are bad, the only way for us is to limit our throughput in order to lower loss,” the refiner added.
As a result, most of the Sinopec refineries are reluctant to make up the throughput reduction due to maintenance in their peers Qilu Petrochemical, Wuhan Petrochemical and Qingdao Petrochemical.
Instead, 11 of Sinopec refineries which are in normal operation cut their runs by 1-7 percentage points in October from September. These included the newly launched 10 million mt/year Zhongke Petrochemical, cutting its run to 77% from 80% in September.
But Jinling Petrochemical raised crude throughputs by 8 percentage points in October before the refiner shuts its 10 million mt/year crude distillation unit and related secondary units for maintenance from mid-November.
PetroChina’s Dalian Wepec refinery, Guangxi Petrochemical, and Yunnan Petrochemical have been required by the headquarters to further cut their run rates by 5-16 percentage points from September levels, while crude runs in other seven PetroChina refineries were relatively marginal, Platts’ data showed.
However, the reduction was compensated in October as Jinxi Petrochemical has ramped up run rates to 67% as it has resumed operation from maintenance in end-September. Its peer Sichuan Petrochemical also lifted run rate by about eight percentage points on the month. The company’s average utilization rate is at 72% in October, flat to the September level, despite dropping from 81% in the same month of last year.
In a summary, 39 state-owned refineries plan to process 6.99 million b/d of crude in October, accounting for 78.9% of their nameplate capacity of 8.86 million b/d, according to information collected by Platts.
Those refineries cover 20 Sinopec refineries, 17 PetroChina refineries, CNOOC’s Huizhou Petrochemical and Sinochem’s Quanzhou Petrochemical.
Around 25 out of the total 39 refineries have cut run rates in October, including a few which were under maintenance, compared with that 19 refineries in September that cut run rates month on month.
China’s refinery throughput has been on a downward trend after hitting a historical high of 14.14 million b/d in June, data from National Bureau of Statistics showed.
In addition, China’s independent refineries also cut run rates slightly in October, responding to narrowing refining margins. These independent refineries collectively account for about 31% of China’s total refining capacity.
The cuts were led by Hengli Petrochemical (Dalian) Refinery, which lowered run rates from about 108% in September to around 105% at its 20 million mt/year refining complex.
Meanwhile, the 45 small sized independent refineries in Shandong province lowered their run rates marginally to 70.6% as of late October, from around 72% in September, according to local information provider JLC. Luqing Petrochemical recently has shut a crude distillation unit due to weak margins.
But the 20 million mt/year Zhejiang Petroleum & Chemical has maintained its run rates at around 110% in October, stable from last month. The company aims to start up a new 10 million mt/year CDU under its 20 million mt/year Phase 2 project by November.
** PetroChina’s 7 million mt/year Jinxi Petrochemical restarted at around Sept. 27 from a scheduled maintenance starting from July 9.
** PetroChina’s 13 million mt/year Yunnan Petrochemical will shut from early December till end-January for around 50-days scheduled maintenance, postponed from October.
** Sinopec’s Qingdao Petrochemical has shut for maintenance from around Oct. 9 for about 50 days.
** Sinopec’s Wuhan Petrochemical has shut for maintenance from around mid-October for about two months’ maintenance.
** Sinopec’s Qilu Petrochemical has shut a 8 million mt/year CDU for maintenance from early September, to last till end October.
** Sinopec’s 21 million mt/year Jinling Petrochemical will shut a 10 million mt/year CDU, as well as some secondary units for about 40-day maintenance since November 17.
** CNOOC’s Huizhou Petrochemical will shut for maintenance over February-April 2021.
Source: Hellenic Shipping
Traders scout for supertankers to store diesel as virus spreads

Oil traders are scouting for newly built supertankers to store diesel for the next few months as they brace for lower demand in Europe amid renewed restrictions aimed at battling the COVID-19 pandemic, shipping and trade sources said.

Trading companies, including oil majors, are making enquiries to charter very large crude carriers (VLCC) to carry diesel with 10 parts-per-million (ppm) sulphur for up to six months, they said, indicating that diesel floating storage could rise again.
Several such supertankers, able to carry 2 million barrels of oil each, have been booked since the second quarter of this year to ship diesel from Asia to the West and others were used to store diesel when demand first tanked earlier this year.
With renewed lockdowns in Europe, traders are concerned that diesel consumption in heating, industrial and transport sectors could be hit. It is unusual for traders to store diesel for months during peak winter demand season.
“Due to a possible second or third wave of coronavirus, inventory storing can be happening under a low freight environment,” a Singapore-based diesel trader said.
“As these are newbuilts, they can sail to demand centres, usually in West Africa or Europe or even the U.S. (to wait for demand to pick up).”
Floating storage is also economical for some traders at current low freight rates and as the benchmark 10ppm gasoil in Singapore has stayed in a contango structure since late-July.
A contango market, where prompt prices are lower than those for future delivery, tends to encourage holders of physical barrels to store a product for selling later to secure higher prices.
For new and clean supertankers coming out of yards, the rate is around $38,000-40,000 per day, two shipping sources said.
Shipowners of newly built VLCCs, which are in abundance this year, are also pricing them at low enough prices for traders to conduct maiden voyages on them, a second trader said.
Source: Hellenic Shipping
Traders Look To Store Diesel At Sea As Second Wave Hits Demand

In another sign that the second coronavirus wave is hitting fuel demand, oil trading firms are looking for new supertankers to use them as floating storage for diesel as demand is expected to suffer from the renewed lockdowns in major European economies, trade and shipping sources told Reuters.

Diesel in global floating storage is expected to increase as major oil firms and trading houses are on the prowl for supertankers, expecting lower than usual diesel demand from the industrial, heating, and transport sector in the coming months.
Concerns about fuel demand intensified this week after two of the largest economies in Europe—Germany and France—announced lockdowns, which the market was not expecting two or three weeks ago. Industry professionals and executives did not believe that countries would resort again to nationwide lockdowns. Yet, France did, and as of Friday, people are allowed to go out only for shopping for essential items, for medical reasons, or for an hour-long exercise. The measure will last until the end of November, French President Emmanuel Macron said.
As the market braces for faltering economic and oil demand recovery, oil traders are reportedly looking to take advantage of the currently low tanker rates and the contango structure of the market to store diesel now with the intention of selling it at a later stage when demand and prices recover.
Middle distillates have been struggling to find markets amid weak demand in recent months. Slower-than-expected fuel demand recovery amid the economic slump and still precariously low aviation fuel consumption have sent distillate stocks around the world to multi-year highs. This, in turn, has led to disastrously low refining margins in every part of the world, discouraging refiners from processing increased volumes of crude into fuels.
Probably one of the strongest signals of a growing global glut in distillates is increased interest from traders to hire oil product tankers to store diesel as floating storage, tanker owners and tanker-tracking firms told Bloomberg in the middle of September.
Source: OilPrice
Japan imported 20.173 mmb of crude from UAE in September

Japan imported from the United Arab Emirates 20.173 million barrels of crude oil in September 2020, data released by the Agency of Energy and Natural Resource in Tokyo, showed.

This accounts for 31.4% of Japan's total crude imports, the agency that belongs to the Ministry of Economy, Trade and Industry, said.
Saudi Arabia provided 25.721 million barrels, or 40.1% of the total, while Kuwait provided 5.139 million barrels or 8.0%.
Japan Imported from Russia 2.190 million barrels or 3.4%. Arab oil accounted for 58.008 or 90.6%, of Japan’s petroleum needs in September. Japan’s total crude oil imports in that month amounted to 64.212 mmb, the agency said.
Source: Argus
BP to shut Australia largest refinery

BP is to convert its 146,000 b/d Kwinana refinery in Western Australia (WA) to an import terminal, in the latest downstream closure to hit the region amid weak markets and rising competition from China.

All refining activities at Kwinana — Australia's largest refinery — will cease in six months, as low margins mean the plant is not economical to run, BP said.
"Regional oversupply and sustained low refining margins mean the Kwinana Refinery is no longer economically viable. Having explored multiple possibilities for the refinery's future, BP has concluded that conversion to an import terminal is the best option," the company's Australia head Frédéric Baudry said.
Refining activity will wind down over the next six months. BP did not say when import terminal operations would begin.
The new terminal, once complete, is likely to support around 60 jobs, less than 10pc of the refinery's 650 workforce.
The refinery relies almost wholly on imported crude. Seaborne crude deliveries to Kwinana have averaged 132,000 b/d since the start of 2018, according to Vortexa data. The majority of this has comprised 47,000 b/d of light sour UAE Murban crude, 42,000 b/d of light sweet Malaysian grades — mainly Kimanis and Bunga Orkid — and 21,000 b/d of US light sweet WTI.
The closure comes despite moves by the Australian government, announced last month, to provide subsidies to refiners as part of efforts boost the country's diesel storage capacity. BP did not comment on those plans in today's announcement.
Kwinana is one of only four refineries left in Australia, following the shutdown of over 300,000 b/d of capacity in 2012-15. It is the country's single-largest refinery and the only plant in the relatively sparsely populated state of WA.
Two of Australia's other refineries are also facing an uncertain outlook and may be converted into import terminals. Ampol, formerly Caltex Australia, is reviewing its 109,000 b/d Lytton refinery in Queensland, while Viva Energy is examining the long-term viability of its 128,000 b/d Geelong refinery in Victoria as margins are hit by slumping demand and regional overcapacity. That leaves ExxonMobil's 90,000 b/d Altona refinery in Victoria as the only plant left without a question mark over its future.
The decision to halt refining activity at Kwinana is a response to long-term structural changes to the regional fuel market, BP said. The conversion to an import terminal will not affect fuel supplies to WA, it added.
BP said it is assessing the feasibility of a large-scale hydrogen export plant at Geraldton in WA in partnership with the federal government. A multi-use clean energy hub could produce and store lower-carbon fuels, including sustainable aviation and marine fuels and waste-to-energy solutions such as renewable diesel, it said.
The company's other operations in Australia are unaffected. These include a one-sixth share of the 16.3mn t/yr North West Shelf (NWS) LNG venture offshore WA, as well as plans to drill the Ironbark gas field in the Carnarvon basin offshore the state.
Asia-Pacific refineries are struggling to compete with rising exports from China, as the Covid-19 economic slump drives down margins. Refining NZ last month said it will operate its 135,000 b/d Marsden Point plant at reduced capacity next year, postponing any immediate plan to convert New Zealand's sole refinery to an import terminal. Shell permanently shut its 110,000 b/d Batangas refinery in the Philippines in August, while fellow Philippine refiner Petron has threatened to close its 180,000 b/d Bataan plant unless it gets more government support.
Source: Argus