China ramped up oil product exports in October even as refiners elsewhere struggle to stay on their feet in what is set to be the new norm as the global refining sector faces up to unrelenting Chinese expansion and COVID-19-induced fuel demand decimation, according to industry sources and government data.
The newly-built highly-integrated mega Chinese refinery-cum-petrochemical complexes are immensely more efficient than the 50-60 year-old clunkers that they are replacing across the globe spanning from the U.S. west coast to the Philippines, bringing a new paradigm to the oil market, they said.
Even though Chinese refineries are built primarily to cater to the domestic market, the export market is a safety valve whenever there is an imbalance in fuel or petrochemical demand, which easily amounts to 1 million b/d in an average month. Such volumes weigh heavily on inefficient, standalone sites that are increasingly exposed and consequently shuttered.
“We have these new refineries coming up in China that were planned 3-5 years ago but China does not need the extra capacity right now, the world also does not need it. We are going to see margins getting worse for refiners in the region and more capacity will be shut,” said one trading source.
The world’s largest crude oil importer shipped out 4.52 million mt of gasoline, diesel and jet-kerosene in October, up 73% from the 2.62 million mt exported in September, General Administration of Customs data showed. The volumes were little changed from a year ago, which were weighed by a 72% collapse in jet-kerosene shipments due to the virtual grounding of international air travel.
Yet at the same time, Chinese refiners, set to become the biggest global refining center at the expense of the U.S., cranked up runs to a record-high of 59.82 million mt, or about 14.15 million b/d, in October even as domestic demand failed to live up to expectations during the autumn holiday season.
The U.S. has an operable refining capacity of about 18.62 million b/d, which shrank to as low as 13.32 million b/d in April 2020 before rebounding to 14.68 million b/d, according to data from the Energy Information Administration (EIA). About 1 million b/d are likely to be permanently shuttered because of poor refining margins due in part to the demand erosion wreaked by COVID-19.
On the other hand, China’s refining capacity is forecast to climb to 20 million b/d by 2025 from 17.5 million b/d at the end of this year, according to the Economics & Technology Research Institute (ETRI) of the China National Petroleum Corp.
“Chinese refineries are not intentionally built or designed to serve the overseas market in the first place, until now many refineries see the export market as their last resort, or a valve to clear up any surplus,” said Feng Xiaonan, IHS Markit downstream analyst in Beijing.
However, Feng concedes that the refiners do enjoy competitive advantages over other regional players if they are relatively free to export and have sufficient government granted quotas.
“The reason is multi-fold, 1. They can bear lower product cracks by leveraging on the more profitable chemicals side. 2. Economies of scale. 3. High production flexibility, e.g. they can intentionally gear up their oil product yield when the market is in favor of these products and vice versa,” she said.
The new sites coming onstream in China typically have processing capacities of 300,000 b/d or more and are integrated with petrochemical units that allow them to swing from a so-called petrochemical to an oil-product mode as the economics dictate.
Two well-known facilities that have come on-stream over the past year are centered around 800,000 b/d crude processing capacities each that stretch downstream all the way to aromatics and ethylene derivatives such as polystyrene and polyethylene among the many plastic products produced.
Earlier this month, China awarded a further 3 million mt of export quotas as part of its final batch for this year, raising the tally for 2020 to 59 million mt from 56 million mt last year, industry sources said.
The volumes suggest that the Chinese government for now is comfortable for its refiners, both state and privately-owned, to have a bigger share of the overseas market which traders said would extend deeper into Australia, New Zealand and the west coast of the Americas where refining capacity is shrinking.
So far in Asia, Royal Dutch Shell announced the closure of its 60-year-old 110,000 b/d Tabangao refinery in the Philippines and plans to cut capacity by half at its biggest 500,000 b/d facility in Singapore. Shell said it aims to have just six integrated refineries by 2025.
BP Australia earlier said it would convert its 152,000 b/d Kwinana refinery in Western Australia into an import terminal. Ampol said Oct. 8 it is studying a similar conversion of its 109,000 b/d Lytton site, echoing a statement by Refining NZ, the sole operator in New Zealand. The Australian government last month announced plans to subsidize refiners as long as they maintain operations in Australia, days after Viva said it may shut the 120,000 b/d Geelong site.
One of the export quota recipient, Zhejiang Petrochemical Corp. (ZPC) was given 1 million mt. The company, which is majority owned by Rongsheng Petrochemical Co., is in the final stages of getting the second phase of its 800,000 b/d refinery up and running.
“One million mt for use in one month is a lot, most of this will end up as gasoline and that will have an impact on the market. We may have to brace for more such news next year,” the trading source said.
--Reporting by Raj Rajendran Rajendran.Ramasamy@ihsmarkit.com
--Editing by Trisha Huang Trisha.Huang@ihsmarkit.com
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Oil product consumption in Asia may recover to 2019 levels next year following the discovery of a COVID-19 vaccine with optimism driven by the robust demand growth already seen in India and China but an immediate boost is unlikely with global demand lagging behind and time needed for a global inoculation program.
Drug makers Pfizer and BioNTech said on Monday that their vaccine was more than 90% effective in preventing COVID-19, raising hopes that the pandemic, which eroded global fuel demand, may be controlled, trading sources said. Crude oil surged on the news with ICE Brent up 6.1% on-day to $42.74/bbl as of 4:30 pm Singapore time.
Transportation fuels such as gasoline, gasoil and jet fuel strengthened on Tuesday in Asia, according to broker data.
"It is good news, although the requirement of very low-temperature storage could pose a logistical challenge. This could be the start of the series of new vaccinations under development. These vaccines will help accelerate the fuel demand recovery," said Premasish Das, IHS Markit research and analysis director.
"They would help all the transportation fuels, but particularly jet fuel can get a boost as it can increase consumer confidence triggering more travel."
Asian demand is expected to exceed the 2019 level in 2021, but global consumption will not recover to the 2019 level before 2023, Das said.
Oil product traders in Asia, however, maintained a cautious stance for now, saying it is premature to expect the vaccine to raise demand immediately.
"It is too early to say as vaccine will anyway be launched by June 2021," said a gasoline trader. "Europe is under lockdown and demand is weak."
The January/March Singapore 92 RON spread remained in contango although the spread shrank to minus $0.80/bbl on Tuesday from minus $0.85/bbl in the previous session.
Pressured by weak demand and supply overhang, the benchmark 92 RON crack on Nov. 4 fell to $2.020/bbl, the lowest since Sept. 3, according to OPIS data. It recovered to $2.654/bbl on Tuesday.
Jet fuel also may not strengthen in the near term due to the logistics involved in getting a global inoculation program running, sources said.
"There may be a small uplift in air travel around mid-to-late 2021, assuming travel bans, restrictive measures are lifted, as people rush to travel after being grounded for so long. But then, it will still take time before market confidence returns to 100%," said April Tan, IHS Markit downstream research associate director in Singaporean.
In the marine fuels market, enquiries are muted as buyers of bunker hold back their purchases after the latest jump in prices.
The high sulfur fuel oil (HSFO) is in steep backwardation with the prompt balance November at least $4.50/mt more expensive than December cargoes, while the very low sulfur fuel oil (VLSFO) is at $1.50/mt in backwardation for the same period, said traders.
Demand could pick up for bunkers from cruise liners once the vaccine proves to be effective as borders open up and travelling resumes, said some bunker suppliers.
In the petrochemical sector, demand for polyester, derived from purified terephthalic acid (PTA), paraxylene and mixed xylene (MX), could improve as a life returns to normal, a petrochemical producer said.
Even if a vaccine reduces demand for propylene from the packaging and medical sectors, the demand loss is likely to be offset by renewed demand from the automotive sector, he added.
"Demand gain from COVID-19 offset only some losses from the other sectors. So, when the world becomes healthy, demand should increase further and that is the basic scenario of IHS Markit GDP and energy price assumption as well," said another IHS Markit analyst.
The surge in pandemic-driven demand for olefins derivatives such as packaging, medical equipment and hygiene products helped to offset the declines in automotive, coatings and durable goods demand.
Mobility curbs delayed the commissioning of new plants while supply of propylene from refinery sources was curtailed as refiners cut runs, according to Asia Light Olefins World Analysis - Propylene.
The factors that supported olefins demand also negatively impacted sectors that consume durable goods made from aromatics, including building, construction and furniture while empty roads meant lower demand for gasoline octane boosters MX and toluene.
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--Reporting by Jongwoo Cheon Jongwoo.Cheon@ihsmarkit.com, John Koh John.Koh@ihsmarkit.com, Trisha Huang Trisha.Huang@ihsmarkit.com and Thomas Cho Thomas.Cho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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A bumper 10 million-barrel spot crude oil purchase by Rongsheng Petrochemical suggests it is keen to get the second phase of its massive 40 million mt/yr, or 800,000 b/d, refinery and chemical project at subsidiary Zhejiang Petrochemical Co. Ltd (ZPC) running in the coming months, trading sources said.
Rongsheng announced in August plans to begin trial runs at the second 400,000 b/d tranche of the project in the fourth quarter of 2020 and looks set to achieve this aim despite COVID-19-related construction delays due to social distancing restrictions earlier in the year.
Market participants said Rongsheng was absent from the spot market for a couple of months and returned this week to buy the medium-sour Middle East cargoes, which led some to believe it was restocking but added that the scale of the purchase does point to some use in the new facility.
"At least part of the purchase can be attributed to the Phase II trial," said one source.
The refiner bought grades including Upper Zakum, Qatar Marine, Basrah Light, Oman and Al-Shaheen, they said, adding that the cargoes were for delivery mostly in December with some going into January, they said.
The purchase is not a sign of increased crude purchases from China for the final quarter as the nation has still to work through record imports made earlier in the year with deliveries in September coming in at a high 11.8 million b/d, up 2% from 11.2 million b/d in August and well above the 10 million b/d a year ago, according to preliminary data from the General Administration of Customs (GAC).
China took in an all-time high of about 12.9 million b/d in June as its extensive spring bargain hunt led to record summer/autumn arrivals resulting in massive port congestion and lengthy vessel wait times that have now eased, the GAC and IHS Markit Market Intelligence Network (MINT) vessel tracking data showed.
"The small recovery in imports is driven more by the temporary release of the backlog as port congestion eased instead of by fresh buying," Feng Xiaonan, IHS Markit downstream analyst in Beijing, said earlier. OPIS is a company of IHS Markit.
The refinery complex is designed to process medium-sour crudes into transportation fuels and feedstock for the petrochemical units.
Secondary refining units at the site include a 3.8 million mt/year reformer, a 5 million mt/year residue fluid catalytic cracker (RFCC), a hydrocracker, naphtha and residue hydrotreaters.
The petrochemical units include a 1.4 million mt/year ethylene and a 4 million mt/year paraxylene plants as well as related downstream polymer and polyester units. It also has a 600,000 mt/year propane dehydrogenation (PDH) unit.
ZPC completed hoisting several of its major refining units, including the crude distillation unit (CDU), residual hydrotreating unit and diesel hydrotreating unit by the time of this update, IHS Markit said in its Aug. 27 short-term outlook on the China crude market.
"Under normal conditions it would take at least another 4-6 months before they can get the entire plant ready for normal operation, but we can't exclude the possibility that they may choose to partially startup Phase II in order to meet their stated goal of a 2020 Q4 startup," Feng said on Friday.
Phase II is centered around a similar 400,000 b/d CDU as the first phase, placing ZPC in conjunction with Hengli Petrochemical as operators of the largest independent refining-cum-petrochemical complexes in China. Once completed there will be two such 800,000 b/d sites in the country.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here.
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
--Editing by Trisha Huang, Trisha.Huang@ihsmarkit.com
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Sentiment remains divided over the direction of European jet fuel prices ahead of winter, following market turbulence which saw fourth quarter 2020 and first quarter 2021 paper tumble between July and August before surging higher from September until early October, sources told OPIS.
Continuing low refinery runs coupled with the autumnal turnaround season has tightened supplies from across the European barrel since September, creating backwardation in naphtha and gasoline and causing middle distillate differentials to strengthen versus distillate futures, according to OPIS and Intercontinental Exchange pricing.
European jet differentials versus front-month ICE Low Sulfur Gasoil futures jumped higher in September, helped by refiners minimizing aviation fuel production as the persistence of COVID-19 stalled the recovery of the sector.
IHS Markit analysts pegged refinery yields at just 2.6% of refinery input in May compared to 7.8% for the same period a year earlier.
Europe, which is structurally short jet fuel and usually imports more than 20 million metric tons a year, mainly from the Middle East Gulf and India, has largely been influenced by Asia, sources told OPIS. The European market has been focused on the strengthening regrade in Singapore, the difference in price between jet and 10ppm sulfur gasoil prices.
"The argument is that we are facing a very cold winter, and Japan will need to buy kerosene and refiners have cut production back. China's domestic aviation market has also bounced back. But I don't buy it myself because Japan's tanks are full, and the long haul (flights) sector is still suffering," one trader said. "There was also talk of jet fuel being blended into marine gasoil pools to help support the market."
At the start of September, the November regrade was trading at minus $5.10/bbl, with Singapore FOB jet paper trading the equivalent of around $18.50/mt below Singapore FOB 10ppm sulfur gasoil paper. By the end of the month, the November regrade had bounced higher to minus $3.08/bbl, while FOB jet paper narrowed to just $5/mt below Singapore FOB 10ppm sulfur gasoil, a contraction of $13.50/mt over the month.
There was a similar pattern in Europe. Q4 2020 jet paper for cargoes arriving CIF northwest Europe was trading around $23.50/mt below Low Sulfur Gasoil futures. By the end of month, Q4 jet paper bounced back to $9/mt below distillate Low Sulfur Gasoil, narrowing the discount by $14.50/mt.
"Most of the European swaps, and it has been volatile, have been trading during the Singapore market-on-close," another trader said. "People think the worst is over, and there is talk of refiners continuing to cut jet production out of the slate, and also expectations some refineries will be axed next year."
But the volatility and liquidity of jet paper raises uncertainty over whether the rally in both the Asian regrade and European paper will hold over the winter. Trading was very thin for Q4 and Q1 jet paper to begin with, although it has started to recover, according to jet fuel traders.
"It was all small bits, and gappy [at first]," said one trader. "It is correcting (now) with good refiner selling seen in last few days."
"I am happy to see the differentials higher, but what struck me as odd was the recovery was the recovery was much greater in Q4 and Q1 than next summer," said a refining source. "The whole of the curve has moved up, but if the aviation market is recovering then I would expected to have seen Q2 and Q3 swaps rally as much as if not more than Q4 and Q1, [which is the period] when demand falls off and when there is still no vaccine."
Differentials for jet fuel cargoes arriving into Europe typically trade at a premium of between $20 and $40/mt above distillate futures and have soared to above $80/mt when the market is short of supply. But the forward pricing curve for jet fuel prices collapsed after COVID-19 struck, as the pandemic grounded aircraft while countries went into lockdown to halt the spread of the virus.
At the end of April, fourth quarter jet cargo paper was trading at minus $3/mt on expectations of recovering demand. But the fourth-quarter swap levels collapsed during July as expectations of a recovery in jet fuel demand this year were dashed by further outbreaks of coronavirus and the imposition of more travel restrictions. By the end of August, the paper had slumped to minus $23.50/mt.
Demand for flying was recovering from the nadir of April until the peak demand month of August, where it reached around half the levels recorded for 2019. But the recovery has since stalled, and by next January, demand is forecast to deteriorate to 60% of January 2020 levels, according to Eurocontol, a pan-European air traffic management agency.
"I am going to quote you what the head of a major trading desk told me a few months ago. We don't know where the jet paper should be," one trader told OPIS.
"It could be minus $40, minus $20, or plus $20/mt."
Get daily expert analysis of the Northwest Europe and Mediterranean jet fuel, ULSD and gasoil markets with OPIS Europe Jet, Diesel & Gasoil Report. Try it free for 21 days.
--Reporting by Paddy Gourlay, patrick.gourlay@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Indian refiners are cranking up runs strongly on the back of robust domestic gasoline demand and signs of a recovery in diesel consumption amid speculation that crude throughput may even reach 100% in December, trading sources with knowledge of the matter said.
Moreover, increased domestic travel going into the holiday season and better manufacturing data have raised expectations for even higher diesel and jet fuel consumption amid wider use of public transportation and air traffic, they said, adding that liquefied petroleum gas use remains healthy.
Refinery runs at the world's third largest crude oil importer are forecast to increase to 90% in November from around 80-85% in October with further hikes anticipated in December, with one source adding that it could reach 100% due to the combination of renewed diesel and strong gasoline demand.
"Gasoline demand is super high and diesel demand is showing some signs of recovery," one India-based source said, adding that the rebound in diesel consumption has allowed refiners to crank up runs which were earlier hamstrung by limited middle distillate demand.
Even though diesel and in particular jet fuel demand is well below year-ago levels, strong month-on-month growth has brought fresh optimism going first into the Dussehra festival in October, followed by Diwali in November, which trading sources said should trigger an increase in demand for transportation fuels.
Another indicator of the changing tide was seen last week when Indian Oil Corp. (IOC), the nation's largest refiner, cancelled a gasoline import tender while seeking to sell the most diesel in a month for at least six years.
"Gasoline recovery has been strong and will receive a modest boost from seasonal demand due to the festive seasons. For diesel, the IHS Markit September Manufacturing PMI was 56.8 (4.8 points higher than August), indicating that industrial activities are recovering well, supporting diesel demand," said Kendrick Wee, IHS Markit research and analysis associate director in Singapore.
IHS Markit estimates Indian refinery utilization at 87-88% in November/December.
Domestic gasoline sales by the three largest state-run refiners, who together have 90% of the local market, grew 2% in September, the country's first monthly year-on-year growth since the March COVID-19 lockdown, the sources said citing preliminary data from the sellers.
Diesel sales were down 7% on-year but up 22% from August, which they said portends to possibly flat growth in October and even year-on-year gains by November.
India reduced refinery throughput in August to 16.1 million mt, or 3.82 million b/d, down a hefty 26.4% from a year ago, according to data from the Petroleum Planning & Analysis Cell (PPAC). This works out to 76% of the country's nameplate 5.02 million b/d capacity and 73.6% of the 5.19 million b/d processed a year ago, the data showed.
Crude oil imports reached 15.2 million mt, around 3.58 million b/d, in August, down 23.4% from a year ago but up by an almost similar margin from July, PPAC data showed. Intake was also the highest since April.
The expectations for fuel demand growth come despite the spread of COVID-19 as India has not instituted new nationwide social distancing measures even as cases soar to almost 6.7 million, the second-largest cases globally. It recently reopened schools.
In Maharashtra state, home to the commercial capital of Mumbai, for example, bars and restaurants were allowed to reopen from Monday, which could trigger a return of workers to the city that is facing staff shortages due to mobility issues.
There are no major refinery turnarounds planned in the fourth quarter aside from the month-long shutdown of the 400,000 b/d Vadinar facility in October.
Consequently, if runs are cranked up to full in December, crude oil trades will increase significantly from this month. Already there were signs of increased runs as purchases of November-delivery barrels rose, trading sources said.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Editing by Trisha Huang, Trisha.Huang@ihsmarkit.com
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Most parts of Japan will likely experience a colder winter this year, the country’s official weathermen said in its first forecast for the season, signaling a possible increase in the import of heating fuels such as kerosene and LNG.
All regions of Japan, except Tohoku and Hokkaido, will have a 40% probability of below-normal temperatures over the winter months of December to February versus a 30% chance of normal or above-normal temperatures, according its first winter weather forecast published by the Japan Meteorological Agency (JMA).
Temperatures over the same period in Tohoku will have a 40% probability of being normal, while those in Hokkaido will have a 40% chance of being above normal, the JMA data showed.
Kerosene
A harsher winter could prompt Japanese traders to increase their kerosene stockpiling for winter from October, bringing some reprieve to the embattled jet-kerosene market that has been severely hit by COVID-19, market sources said.
“Market players are seeking outlets for their jet fuel and kerosene due to the pandemic which hurt the aviation industry,” a trader said, adding “a cold winter forecast may drive kerosene sale and prices.”
Asia jet fuel crack showed signs of strengthening in recent weeks, albeit still in the negative. Refining margins was at minus $0.05/bbl at the end of last week, up from minus $2.28/bbl on Aug. 31, which was the lowest point in more than three months.
But some trade sources, on the other hand, remain skeptical about the impact that the colder winter in Japan may have on the wider jet fuel market.
“The crack may not be able to reach half of the values in 2019 as year-end tourism is usually the main driving force behind kerosene and jet fuel,” one of the traders said.
Jet fuel crack averaged plus $15.70/bbl over October to December 2019, OPIS data showed.
Any improvement in kerosene demand this winter would be a welcome change for sellers compared with last year when milder temperatures weighed on the country’s buying appetite for the heating fuel.
Japanese kerosene imports in December 2019 to February 2020 dropped to an average of 3.66 million bbls per month, down by 6.4% from 3.91 million bbls over the same period in 2018-19, data from the Petroleum Association of Japan (PAJ) showed.
Kerosene, which is essentially jet fuel with a few minor differences in its specifications, is widely used in small heaters throughout Japan during winter.
LNG
Colder weather over the peak gas demand season of winter could also boost Japan’s LNG demand and offset some of the COVID-19 negative impact on demand for the super chilled fuel this year, traders said.
“Cold winter weather in a major demand center like Japan is definitely a boost to overall fundamentals. In the very least, it will help pare the current high inventories in the country,” said a northeast Asian trader.
Japanese gas stockpiles have stayed high during the COVID-19 outbreak, which not only crimped spot purchases but also spurred the deferments of many long-term cargoes by importers earlier this year.
Several Japanese buyers exercised the downward quantity tolerance provision in their offtake contracts to cut long-term volumes, sources said.
Tepid year-to-date LNG demand is seen in sluggish import volumes, which fell to around 55 million mt from January to September 2020, 4.8% lower than the same time last year, according to shipping data by IHS Markit LNG Analytics.
But the latest colder weather forecast may have already started to turn the tide, a Japanese trader said, citing the emergence of three Japanese utilities in the spot market last week for October and November cargoes.
However, a second Japanese trader warned that any increase in LNG imports this winter might be modest.
“This winter’s total LNG imports into Japan won’t be as much as in previous cold winters as we are still working through pretty high inventories and are still facing reduced demand from COVID-19,” the trader said.
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--Reporting by John Koh, John.Koh@ihsmarkit.com, Carrie Ho, Carrie.Ho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
Copyright, Oil Price Information ServiceEgypt's Middle East Oil Refinery (MIDOR) company, located in Alexandria, has issued a tender to buy 90,000 metric tons of gasoil for October and November delivered into El Dekheila Port, according to a document seen by OPIS amid better-than-expected recovery in the region.
MIDOR is seeking one 30,000 mt (plus or minus 10%) cargo of 1% maximum sulfur gasoil for delivery to El Dekheila over October 11-13; one 30,000 mt (plus or minus 10%) cargo of 0.5% maximum sulfur gasoil for delivery over November 5-7; and one 30,000 mt (plus or minus 10%) cargo of 1% maximum sulfur gasoil for delivery over November 20-22. Bids should be submitted by September 28 and are to remain valid until October 2, according to the document.
Demand in Egypt seems to be recovering quicker than expected.
"We started to see some recovery in July/August and recent tenders from MIDOR and Egyptian General Petroleum Corporation (EGPC) are reflecting the recovery, but demand is still lower than last year at this time," said Farrah Boularas, an associate director with IHS Markit Downstream.
With the largest oil product market in Africa, Egyptian total inland product demand has grown at an annual average rate of 2.4% since 2012, reaching an estimated 916,000 b/d in 2019, reports IHS Markit, the parent company of OPIS." Before the COVID-19 crisis, the net gasoil import balance in Egypt was around 150,000 b/d on average; our base case scenario estimates the gasoil deficit to decrease to at least 100,000 b/d in 2020," Boularas said.
COVID-19 restrictions in Egypt were introduced in March and were gradually eased throughout June. Commercial flights and international tourism to Egypt resumed on July 1.
Of the available data to July, MIDOR imported roughly 63,000 mt of gasoil in June over two cargoes, some 33,000 mt of gasoil in May, almost 33,000 mt of gasoil in March, 33,000 mt in February, and two cargoes of gasoil totaling around 65,760 mt in January however, no gasoil was imported in April or July, according to its website. Exports on the other hand, consist almost entirely of jet fuel.
MIDOR delivers refined products to the national oil company, EGPC, and the local market. Its refinery has a crude distillation capacity of 100,000 b/d and is one of the newest and most sophisticated of Egypt's nine operating refineries, according to IHS Markit data. Egypt has a total atmospheric distillation capacity of 737,000 b/d.
EGPC owns a 78.7% stake in MIDOR, with the remaining equity held by Petrojet (10%), Engineering for Petrol and Process Industries (10%) and Suez Canal Bank (1.3%).
MIDOR didn't respond when contacted by OPIS for comment.
Get daily expert analysis of the Northwest Europe and Mediterranean jet fuel, ULSD and gasoil markets with OPIS Europe Jet, Diesel & Gasoil Report. Try it free for 21 days.
--Reporting by Jen Caddick, jenny.caddick@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Heavy full range naphtha (HFRN) traded at a bigger discount to lighter or cracker grades in Asia amid ample arbitrage barrels as splitter operators shun heavier grades with high jet-kerosene yield, the demand for which is decimated by COVID-19 mobility restrictions, market participants said.
HFRN traded at a discount to open-specification naphtha (OSN) with minimum 70% paraffin since late June as soft aromatics margins and lower splitter runs crimped demand. While paraffinic naphtha continued to trade at premiums to Japan assessments, discounts for HFRN steepened.
On Wednesday, Hanwha Total Petrochemical (HTC) bought HFRN for H1 Nov. to Daesan at a discount of $5/mt or larger to Japan prices, said sources. An HTC company source declined to comment.
On Thursday, Yeochun NCC (YNCC) bought OSN (minimum 70% paraffin) for H1 Nov. at plus $4.50/mt, effectively placing the HFRN-OSN spread at $9-$10/mt, bigger than the $5-$6/mt in mid-September.
Last Friday, GS Caltex bought H1 Nov. HFRN at minus $3-$5/mt but the absence of H1 Nov. OSN deals until Thursday meant that a meaningful comparison was not possible at that time.
Given that HFRN values are grade dependent, for the purpose of price discovery it is equally important to find out the specific grade purchased by HTC, a trader cautioned, adding that splitter operators currently prefer B grade HFRN with a lower jet-kerosene yield than A grade.
"Nobody wants A grade now. If given a choice, any splitter operator would pick other HFRN. B grade with less jet-kerosene is more attractive to buyers," the trader said.
So-called A grade is splitter grade HFRN while B grade is swing grade that can be used by either splitter or cracker, a source explained. Shipments from the Black Sea ports of Tuapse and Novorossiysk are classified as A grade, although Novorossiysk barrels tend to be the lighter of the two with variable specifications, the source added.
A driver of the recent HFRN price slide versus OSN could be due to some grades that are jet-kerosene rich, another trader said, adding that exports from Tuapse typically have a higher yield of the middle distillate.
"Buyers prefer whatever that has lower jet-kerosene. Some grades are full of kerosene which could explain the low premiums," the second trader said.
Despite the deepening HFRN discount and the relatively high freight rates for the benchmark Mediterranean-to-Japan route in recent weeks, the inflow of HFRN is unlikely to ebb because Europe needs to export surpluses to Asia, market participants said.
"Tuapse doesn't have many alternative outlets in Europe; cargoes still have to come to this region," the first trader added.
Monthly exports from the Russian Black Sea to East Asia averaged about 440,000 mt for the year to August, with 85.4% of the barrels landing in South Korea, IHS Markit Commodity at Sea (CAS) data showed. Inflow from the Russian Baltic Sea is not included.
Shipments in 2019 averaged 450,000/month, the data showed.
"Structurally, Europe needs to export at least 700,000-800,000 mt/month," a source added.
Rates to carry 80,000 mt of naphtha from the Mediterranean to Japan, a route known as TC15, topped $30/mt on Sept. 15 and held at this level until Thursday, compared with $26/mt a month ago, according to the Baltic Clean Tanker Index.
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--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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The U.K.-based Grangemouth petrochemicals plant operated by Ineos will shut down at the beginning of October, according to sources with links to the plant Tuesday.
The shutdown of the petchems facility in Scotland is planned to last between five and six weeks, those local sources say, and has been pushed back from a provisional mid-September start date.
Turnarounds at the nearby 210,000-b/d Petronineos-operated refinery and the petchem plant were originally scheduled for April this year, but the onset of the COVID-19 pandemic scotched those plans.
One source told OPIS that a short period of maintenance work on a 110,000-b/d crude distillation unit at the refinery was about to end, and so many workers engaged in that project will be redeployed to work on the forthcoming petchems plant shutdown.
A spokesman for Ineos said that the company does not comment on its day-to-day operations at Grangemouth.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Rob Sheridan, Rob.Sheridan@ihsmarkit.com
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Indian refiners are eyeing modest run hikes in the final quarter of this year following healthy fuel demand growth in the first half of this month but ample diesel and gasoline inventories will cap product output growth, industry sources said.
They also caution that should the government revert back to hard COVID-19 lockdown measures -- which thus far they have been reluctant to enact despite soaring new cases due to the hefty economic costs -- whether the nascent growth seen so far will quickly come to a grinding halt.
"Basically there is still a lot of inventory to be cleared up, gasoil is still worrisome considering its half of production and gasoline as well. However, there are some chances to increase runs in November. The festival season calls for it," said one refining source based in India.
India, the second-largest crude oil importer in Asia, reduced refinery throughput in August to 16.1 million mt, or 3.82 million b/d, down a hefty 26.4% from a year ago, according to data from the Petroleum Planning & Analysis Cell (PPAC). This works out to 76% of the country's nameplate 5.02 million b/d capacity and 73.6% of the 5.19 b/d processed a year ago, the data showed.
Crude oil imports reached 15.2 million mt, around 3.58 million b/d, in August, down 23.4% from a year ago but up by an almost similar margin from July, PPAC data showed. Intake was also the highest since April.
Total petroleum products consumption in August 2020 was at 83.8% of year-ago volume at 14.4 million mt versus 17.2 million mt in August 2019, according to the PPAC data. This is down 7.5% from 15.56 million mt in July.
However, sales in the first-half of September by the country's three largest domestic suppliers showed better growth traction.
Diesel sales by Indian Oil Corp. (IOC), Bharat Petroleum Corp. Ltd. (BPCL) and Hindustan Petroleum Corp. Ltd. (HPCL) edged up 19.7% from 1H August to 2.13 million mt, while gasoline and jet fuel rose 7.2% and 21.3% to 965,000 mt and 125,000 mt, respectively, according to data from the suppliers.
"We expect the demand recovery to continue and that would support higher refinery runs in October/November. However, from a year-on-year point of view, there is still a long a way to go to reach the 2019 level," said Premasish Das, IHS Markit research and analysis director.
IHS Markit estimates September refinery runs at 4.1 million b/d, rising to 4.4 million b/d in October/November, Das said, adding that the forecast may be slightly on the optimistic side.
India will be celebrating two major festivals in the coming months, firstly Dussehra in October, followed by Diwali, the important festival of lights, in November, which trading sources said should trigger an increase in demand for transportation fuels.
However, the unrelenting spread of COVID-19 cases has cast a cloud over the upcoming festivities and some are questioning if expectations of exuberance and the accompanying surge in fuel consumption may be over stated especially as attendances at newly re-opened schools were poor, according to a Press Trust of India report.
India now has the second-largest COVID-19 case load at 5.56 million and daily new infections appear to be slowing down with 75,000 reported in the past 24 hours to Tuesday morning, government and John Hopkins data show. Almost 90,000 people have died from the pandemic.
Gasoline and diesel consumption averaged year-on-year growth of 9.35% and 4.8% respectively, since 2011, according to PPAC data.
However, in the COVID-19 affected April-August months, gasoline and diesel consumption was down 25.3% and 28.5%, respectively, from the same period a year ago, PPAC data showed.
Major Indian refiners such as IOC and Reliance Industries have in the past month restarted large facilities at Panipat and Jamnagar, respectively, which should raise crude throughput going forward, the sources said.
In August, IOC processed 3.9 million mt versus 6 million mt a year ago and over the same period Reliance churned through 1.4 million mt at its export-oriented site compared with 3.2 million in 2019 due to maintenance works, the PPAC data showed.
Fourth quarter run rates may edge closer to the 80% mark but is unlikely to breach 90%, they added.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here.
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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An OPEC+ move to extend the compensation period for nations that failed to fulfill output cuts to end-December suggest that the UAE, one of the bigger violator, is likely to stretch already announced crude oil supply reductions in October and November into December, trading sources said.
Abu Dhabi National Oil Co. (Adnoc), the biggest oil producer in the UAE, informed term customers of a 25% cut to November loadings on Wednesday after surprising the market early this month with a 30% reduction to all four of its export grades. The UAE pumped 3.11 million b/d in August or 520,000 b/d above its compliance target, the International Energy Agency (IEA) said in its monthly oil report published on Tuesday.
UAE Energy Minister Suhail Al Mazroui said the over production was due to peak summer power demand and announced in a Sept. 1 tweet of supply cuts. The Adnoc announcement, combined with stricter compliance and compensation by Iraq, has in recent days bolstered Middle East crude oil prices, the sources said.
"Adnoc is already talking to its customers of a cut in December, there is no formal announcement yet like that for October and November," said one trading source, adding that most Middle East grades are currently trading at premiums to their official selling prices (OSPs) from discounts last month.
Murban, the UAE's single-largest crude blend, was last estimated at around $0.20/bbl above its OSP compared with a discount of about $0.70/bbl last month, the source said, adding that some of the gains were also due to the deep cuts made in the latest round of OSP announcements. Upper Zakum, another big export grade, was at around plus $0.10/bbl versus minus $0.70/bbl a month ago.
The price bump were triggered by the cut to supplies which caused an initial knee-jerk buy reaction that reverberated across the various spot traded crude oil markets in the region leading to higher flat prices and firmer time spreads.
The Month 1-3 Dubai time spread, an important indicator in the Saudi Aramco OSP calculation, firmed to about $0.50/bbl in contango on Friday compared with the average minus $0.65/bbl in August, the sources said, citing broker data.
On the other hand, Basrah crude from Iraq has been losing ground in anticipation of increased supply for November after the country managed to claw back a significant portion of its over production in August and now in September, the sources said.
"Output cuts from Iraq will be less in October after they did quite well in August and we are seeing the same in September," the source said.
Basrah Light crude, which traded at around a $0.50-$0.60/bbl premium last month is now edging down towards parity to its OSP, while Basrah Heavy has dipped to plus $0.50-$0.60/bbl from +$1.00/bbl over the same period, they said.
In its statement on Thursday following a Joint Ministerial Monitoring Committee (JMMC) meeting under the leadership of the Saudi and Russia oil ministers, the group said that the monthly report prepared by its Joint Technical Committee (JTC) showed overall compliance by participating OPEC and non-OPEC countries at 102% in August 2020, including Mexico as per the secondary sources.
However, it said the group was looking closely at market developments particularly as new cases of COVID-19 spread in many countries affecting fuel demand. In its monthly report, OPEC downgraded global oil demand further by 400,000 b/d, now contracting by 9.5 million b/d to 90.2 million b/d.
This is in line with similar downgrades by others including the IEA as COVID-19 continues to decimate oil demand, particularly jet fuel as much of global international flights stay grounded.
The JMMC agreed to extend the compensation period until the end of December 2020, "after pledging that they will fully compensate for their overproduction. This is vital for the ongoing re-balancing efforts and helping deliver long-term oil market stability," according to the statement.
The need for better compliance and compensation was driven hard by the Saudi oil minister who warned nations against over producing and then making up for their indiscretions in a news briefing after the meeting, according to several media reports.
"Anyone who thinks they will get a word from me on what we will do next, is absolutely living in a La La Land...I'm going to make sure whoever gambles on this market will be ouching like hell," Prince Abdulaziz bin Salman was quoted as saying in a Reuters report when asked about OPEC+ next steps.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here.
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Saudi Aramco reduced its October liquefied petroleum gas (LPG) term supplies, on a voluntary basis, amid regional demand lulls after keeping allocations in line with nominations for two months amid higher overall term contract volumes for the full year from 2019, according to sources.
Around three cargoes of very large gas carrier (VLGC) size were either cancelled or deferred by mutual agreements, while some other buyers received advanced dates, said sources, adding that at least two of the cuts were to traders.
The LPG term allocations were announced shortly after the Joint Ministerial Monitoring Committee (JMMC) meeting held on Thursday evening, where Saudi Arabia oil minister Abdulaziz bin Salman said that all countries that overproduced need to compensate for exceeding their output quota.
Aramco set in end-Aug. its September Contract Price (CP) for propane at $360/mt, unchanged from August and butane at $355/mt, up $10/mt on-month, as term discussions for next year got started. No cancellations of term cargoes were reported for September.
The October propane CP swap was assessed at $371/mt on Thursday, $11/mt above the September CP, having reached a bottom at $347/mt on Sept. 11 since the September CP was set in end-August.
The kingdom slashed term cargoes in six of the 10 months this year, with a brief boost to eight in April and made no change for July and August, while the total reduction coming up to 21 parcels, based on OPIS record.
It could have sold more cargoes on term contract this year compared to last year, and as a result, some monthly cut seems unavoidable, said market sources.
The country shipped out 495,000 mt of LPG in August, well below the monthly average of 665,750 mt and down 37% on-year, while Its January to July flows totaled 4.75 million mt, a 5% increase on-year, according to OPIS waterborne data.
A few importers did not nominate for the month, based on OPIS record.
Other Middle East producers including Abu Dhabi National Oil Cor. (Adnoc), Qatar Petroleum (QP) and Kuwait Petroleum Corp. (KPC) did not cancel any term liftings for October, despite Adnoc notifying term customers of a 30% cut to crude oil volumes next month. According to sources the producer may have sufficient inventory.
Three free-on-board (FOB) October loading cargoes were sold via tenders by Middle East suppliers so far.
QP sold in early Sept. a 45,000 mt propane parcel for loading from Ras Laffan in early-Oct., while KPC sold one 11:33 lot for early-Oct loading and another 22:22 for Oct. 17-18 loading, based on OPIS record.
--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here.
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A string of very larger crude carriers (VLCCs) were snapped up in the past week as traders took the opportunity of tumbling freight to replace costly time charters (TCs) made earlier at the cusp of the super contango with bookings done at up to one-fifth the price six months ago, according to ship brokers, trading sources and fixtures.
The slew of charters raised expectations of a new round of a buy-now, sell-later trading strategy, or more commonly known as a contango or storage play, but traders said the forward price curve do not yet support such a move.
However, they were quick to add that current exceptionally cheap freight makes such a punt worth exploring as participants work to bring down their storage costs with some taking additional shipping length in the chance that a contango play develops. Such plays have earned trading outfits billions in profits and were also responsible for hefty earnings in the past quarter as oil companies grapple with low prices and poor margins due to the coronavirus disease 2019 (COVID-19)-led fuel demand destruction.
"The contango is not wide enough for an outright contango play. They were hired because tankers were cheap and if the crude market gets worse, then they can use it as contango play," one trading source said, adding that many of the fixtures were also replacements for those done on six-month TCs back in March and April.
According to shipping reports obtained by OPIS, 24 VLCCs have been booked on mostly three-six month TCs with one trading company having got the jump on others and managing to snap up at least four supertankers at below $30,000 per day with the cheapest at $25,000/day. The best deal on the list was for a 3+3-month booking delivered Singapore at $20,500/day, the list showed.
Later bookings were mostly done around the $50,000/day mark with most leading trading companies as well as Chinese national firms among the charterers, the list showed.
This compares with similar six-month TCs done in late April at as much as $130,000/day with many agreed at above the $80,000/day mark, according to past fixture reports.
Included in the list are three newly-built VLCCs, the Hunter Idun, CSSC Liao Ning and the Babylon, which were laden with middle distillates in their maiden voyage and may continue to carry clean products throughout the TC period due to ample diesel and jet fuel supplies and a better contango structure, trading sources said.
Large oil companies with a strong trading team, such as Glencore, Vitol, Trafigura, Gunvor, bp, Total and so forth, holding deep pockets and capacity to execute such costly contango plays typically reap rewards in the billions.
"Marketing adjusted EBIT of $2 billion (H1 2019, $1 billion) reflected oil, in particular, benefiting from the volatile and structurally supportive marketing environment," Glencore said in its first-half results, adding that this allowed the company to raise full-year guidance to the top end of its long-term $2.2-$3.2 billion range.
If there was any doubt as to which part of their business was responsible for the bumper earnings, Glencore said: "There were consistently good contributions across the board, however, oil in particular was able to capitalize on the presence of exceptional market conditions during the half."
The market condition refers to the super contango that developed after OPEC and Russia failed to agree on an output reduction agreement, leading to Middle East producers opening their oil taps and slashing prices, which coincided with the COVID-19 demand decimation to send prices tumbling at vast discounts for prompt cargoes versus forward barrels.
Back in late March, the forward curves showed a six-month contango of $10.50/bbl for Brent, $6.90/bbl for Dubai and $9.90/bbl for WTI. At the same time, physical differentials against these benchmarks sank to historical or multi-year lows in just about every producing region including the Middle East, North Sea, Russia and West Africa, traders said.
For example, Dated Brent, used to price as much as two-third of all global crude oil, fell to a discount of about $10/bbl to front-month ICE Brent, they said. However, for now the numbers have yet to come anywhere near such a dire situation with Dated trading at flat to a modest premium to ICE Brent, they added.
A similar picture emerges on the forwards, which while in contango is about one-third of that chalked in the last super cycle with the six-month spread at -$3.10/bbl for Brent, -$2.50/bbl for Dubai and -$2.80/bbl for WTI, sources said.
However, the latest increase in output from the OPEC+ group and continued lackluster demand due to a resurgence of COVID-19 cases amid fresh lockdown measures have raised the specter of another super contango, the trading sources said.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Saudi Aramco is on cue to slash its October official selling price (OSP) to refiners in Asia by about $1.20/bbl for its biggest Arabian Light grade after below expectations cuts in September in the face of lower spot prices and a slowdown in fuel demand, trading sources said.
The world's largest crude oil exporter cut its Asia September OSP for Arabian Light to buyers in Asia by $0.30/bbl, half of market expectations shaped late month weakness. However, the reduction was in line with full-month average Dubai forward price structures.
In October, a bigger cut is on the cards at $1.00-$1.50/bbl as prevailing Middle East spot crudes lost a lot of ground, the sources said. The Dubai Month 1-3 spread is firmly in contango at an average of around minus $0.65/bbl in August compared with a premium of about $0.70/bbl in July, they said. That’s a $1.35/bbl swing.
“All the Middle East barrels are overpriced, Aramco has to make a big adjustment after last month,” said one trading source, admitting that the producer did not face great difficulties placing its September-loading crude even though it only made minor cuts to its OSP.
“There were some refiners who nominated very little for September after the OSP announcement but Aramco still managed to place their barrels. They have a lot of tricks, with so many different buyers,” he added.
Forecasts for the bigger cuts still held on Tuesday following unexpected news of a 30% cut by Abu Dhabi National Oil Co. in its October term loadings across all four grades in compliance with its OPEC+ obligations, according to a notice to buyers. The promise of a supply reduction temporarily boosted spot prices but it failed to change the price structure, Dubai crude remains entrenched in contango,
Aramco is forecast to cut its Arabian Extra Light by a bigger $1.30-$1.40/bbl due to continued weakness in the gasoline and even naphtha markets as driving was curbed by fresh outbreaks of the coronavirus disease 2019 (COVID-19) despite seasonal peak demand in the northern hemisphere. In September, the OSP was also reduced by a larger $0.50/bbl, a pricing list showed.
Naphtha usage as petrochemical feedstock was crimped by poor aromatics margins as downstream polyester and other derivative demand started to slow down in the face of the prolonged economic downturn wreaked by COVID-19. However, consumption in China for use in olefin production remains robust, a source said.
The heavier Arabian Medium and Heavy grades may see a smaller reduction due to better fuel oil demand, the trading sources said, adding cuts maybe around the $0.90/bbl mark. The OSP of both blends were dropped by a similar $0.30/bbl to the Arabian Light.
Another component in the making of the OSPs is flows from Saudi Arabia, which is less than that allowed under the OPEC+ accord, the trading sources said.
“Saudi is producing about 300,000 b/d less than their quota in August, they should have raised it by 500,000 b/d but there is a shortfall. So it also depend if Aramco wishes to use up all this slack by pumping out more in October,” another trading source said.
Due to its diverse demand base, Aramco has not faced an across-the-board requests for cuts to loading nominations as COVID-19 has had varying impact on nations in Asia with some enjoying a purple patch whilst others were in the doldrums and vice-versa, the sources said.
In China, crude imports for the rest of 2020 is expected to be capped by their massive purchases earlier this year that is still causing port congestion and ullage issues, they said.
“For the rest of the year we do not expect so much crude imports, fresh arrivals have already started to decline. The storage economics have worsened and there are high demurrage costs,” said Sophie Fenglei Shi, downstream research associate director at IHS Markit in Beijing. OPIS is an IHS Markit company.
In its latest short-term outlook on the China market dated Aug. 27, IHS Markit said that preliminary vessel tracking shows that there is still as much as 14 million b/d of crude waiting to be discharged in August, of which at least 3.5 million b/d is delayed from July and even June.
“We expect port congestion will be alleviated in September with less fresh arrivals coming in, and that China’s crude imports will begin to see a material step-down in October and beyond once the congested cargoes get fully cleared,” according to the report.
Demand in India will increase as two massive crude units, the Indian Oil Corp. 300,000 b/d Paradip refinery and a 380,000 b/d unit at the mega Reliance Industries Jamnagar site begin operations after around a three-week maintenance.
“The run rates won’t increase but we have units returning from turnaround,” a refining source in India said.
South Korean crude imports fell by the most in over a decade in August to 77.2 million bbls (2.49 million b/d), down 20.4% from a year ago and 10.6% on-month, preliminary data from the Ministry of Trade, Industry and Energy showed on Tuesday. Purchases dropped by 20.5% in November 2009.
These signs point to a challenging demand environment, which suggest Aramco is likely to heed customer requests for a bigger cut in October unlike what happened in September, the sources said.
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.comGain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Chinese state-owned refining majors plan to export the biggest volume of clean oil products since the depths of the coronavirus disease 2019 (COVID-19) pandemic in April as higher summer runs led to brimming local tanks forcing many to turn to the overseas market, trading sources said.
The four refiners, PetroChina, Sinopec, China National Offshore Oil Corp (CNOOC) and Sinochem, plan to export 3.77 million mt of gasoline, diesel and jet fuel in September, according to a source with knowledge of the matter.
Diesel shipments will increase 10.9% on-month in September to 1.93 million mt, the highest since March while gasoline will drop 2.1% from August to 1.43 million mt, the data showed. Jet fuel exports, on the other hand, will shrink to 410,000 mt, almost a quarter of the 1.58 million shipped out on March.
"Demand on gasoline is showing signs of recovery in China as with other countries as COVID-19 measures were relaxed, enabling people to commute and travel to work again," a trade analyst said.
"Gasoline exports planned for September is lower than that in August given that Chinese refiners are expecting an increase in domestic demand," the analyst added.
On the other hand, middle distillates are feeling the weight of slower regional demand since early July following a resurgence of COVID-19 cases in pockets across the region with some on the verge of turning into a second wave.
The front-month diesel time-spread averaged at $0.28/bbl in backwardation in July, but flipped to $0.33/bbl in contango in August, according to OPIS data. The jet fuel contango widened in August to $0.75/bbl compared to $0.57/bbl in July.
"The increased volume of transportation fuels flowing into the market is going to add further pressure on cargo differentials that are already in the negative zones," a trader said.
"Traders will compete by lowering their offer prices in order to sell off their inventories," he added.
Singapore 10 ppm gasoil and jet fuel cargo differentials are currently at minus $0.35/bbl and minus $0.95/bbl, respectively, while 92 RON gasoline is at minus $0.10/bbl, according to trade sources.
A month ago, prices for 10 ppm gasoil and jet fuel were at plus $0.23/bbl and minus $0.36/bbl, respectively, with 92 RON gasoline at minus $0.39/bbl, OPIS data show.
Chinese refiners faced excess domestic supply of transportation fuels after the economy was again disrupted by COVID-19 outbreaks in July, coupled with heavy monsoon floods in various parts of China.
"Chinese refiners have a big volume of crude to process as they went into the market to buy a lot of cheap crude during the April price crash," another analyst said.
Chinese refiners went on an extensive bargain hunt in spring when ICE Brent crude prices sank to as low as under $20/bbl, which ended up in record shipments in the summer that is now extended to autumn, trading sources said.
The world's largest crude importer took in an eye-watering 53.18 million mt, or about 12.9 million b/d, in June, easily bypassing the previous record 11.3 million b/d that landed in May, according to Chinese General Administration of Customs data.
Refiners ramped up production in July with expectations that domestic economy will recover after the imposed COVID-19 lockdowns were lifted.
Production of gasoline, diesel and jet fuel rose in July by 10.2%, 3.9% and 5.4% to 11.78 million mt, 15.1 million mt, and 3.32 million mt, respectively, according to Chinese National Bureau of Statistics.
Sinopec restarted its 460,000 b/d Zhenhai Refining & Chemical Co. site in July after a four-month maintenance and its 250,000 b/d Tianjin facility after a two-month turnaround, leading to the higher output.
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--Reporting by John Koh, John.Koh@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Naphtha buyers including Yeochon NCC (YNCC) and LG Chem paid higher premiums for their 2021 CFR term purchases than this year as the startup of a wave of new crackers in the coming months and next year shaped views of a tighter supply outlook, market participants said.
YNCC settled at a premium of around $7/mt to Japan naphtha price, two sources said. LG Chem concluded at plus $6-$7/mt while Korea Petrochemical Industry Co. settled at around plus $3/mt, according to several sources. Formosa Petrochemical Corp. (FPCC) bought cargoes for Oct. 2020-Sept. 2021 at plus $4-$5/mt.
These term deals were agreed with trading companies, said a buyer, adding that producers including Saudi Aramco, Abu Dhabi National Oil Co. (Adnoc) and Reliance Industries Ltd. also have trading arms.
“Generally, recent terms were concluded at higher levels than 2020,” said a trader.
Asia naphtha demand as a petrochemical feedstock will continue to grow as new crackers begin operations even as below-capacity refinery utilization rates in some countries squeeze supply further, they said.
In China, Liaoning Bora, Sinochem Quanzhou and the Sinopec-KPC joint venture are set to commission their mixed feed crackers in the coming months, according to analysts and the latest IHS Markit Asia Light Olefins Monthly Analysis.
PTT Global Chemical, Thailand's biggest ethylene maker, will add a new 500,000 mt/year naphtha cracker by December while in South Korea, YNCC is set to complete an expansion by early 2021, boosting the capacity of one of its three plants by 60% to 930,000 mt/year, according to the Monthly Analysis.
In addition, Lotte Chemical plans to restart its fire-hit Daesan cracker by end 2020, the company said earlier this month, adding it plans to diversify feedstocks and will more than double its use of liquefied petroleum gas (LPG) in three years.
While the buyers refrained from disclosing price details because the discussions were confidential, at least two said the negotiations were not easy.
“It has been very tough to negotiate with traders who strongly believe the market will be stronger next year,” said a buyer.
“The offers were a bit higher than expected, so this time we covered just part of our term requirement,” said another buyer.
The concluded 2021 prices, at mid-to-high single digits, also surprised to the upside because they were higher than paper values, two market sources said.
“When FPCC concluded, the 2021 paper curve was around flat, and the idea is that those premiums should follow paper,” said another trader.
The YNCC price was $3-$4/mt higher than what the paper market was indicating at the time, another source added.
Buyers currently in 2021 CFR term discussions include Hanwha Total Petrochemical for splitter grade, or heavy full range naphtha (HFRN), and Lotte Chemical Titan for light naphtha, sources said
Refinery run rates in Asia and the Middle East are expected to improve to 74% this month and reach 82% by January 2021, from below 70% in April during the depth of coronavirus disease 2019 (COVID-19) lockdowns, said April Tan, IHS Markit associate director in Singapore.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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A Royal Dutch Shell refinery in the Philippines became the first Asian casualty of the fuel demand destroying coronavirus disease 2019 (COVID-19) pandemic as other sites in the region brace themselves for similar fallouts in the face of new virus outbreaks and poor refining margins while more sites come onstream in China.
Pilipinas Shell Petroleum Corp said on Thursday that its near 60-year-old 110,000 b/d Tabangao refinery in Batangas province was no longer economically viable and would be turned into an import terminal.
“Due to the impact of the COVID-19 pandemic on the global, regional and local economies, and the oil supply-demand imbalance in the region, it is no longer economically viable for us to run the refinery,” Pilipinas Shell President and CEO Cesar Romero said in the statement.
Refining margins in Asia are under tremendous pressure due to the sharp drop in fuel demand with the benchmark Singapore complex gross margin dropping to minus $3.78/bbl in May/June, according to an update by Refining NZ, which is studying the possibility of converting its refinery in New Zealand to an import terminal.
“This is not a surprise. We are working on a list of refineries in Asia that are vulnerable because of COVID-19 and this refinery keeps coming up in many of the criteria,” said Premasish Das, IHS Markit downstream research and analysis director, adding that there are sites in Japan, Australia, New Zealand and even in Singapore that face uncertain futures.
The Philippines closure will be a boon to the overall Shell system, given its mega refining complex in Singapore with a 500,000 b/d processing capacity, which will now have a new captive outlet as the unit in Tabangao was operating at around 80-85% of capacity prior to its temporary closure in May due to COVID-19, trading sources said.
“The Shell Singapore system could be supported when demand recovers next year,” said one source, adding that transportation fuels such as gasoline, jet fuel and diesel as well as bitumen will be among the products that will be shipped from the Singapore Pulau Bukom site.
The new Tabangao import terminal will cater to the fuel needs of Luzon and Northern Visayas, while the North Mindanao Import Facility (NMIF) in Cagayan de Oro will serve the growing energy needs in the balance of the Visayas islands and the entire Mindanao region, Pilipinas Shell said in the statement.
The permanent shutter will open up a new market for the recently-built refineries in neighboring countries such as the Maura site in Brunei and Pengerang in southern Malaysia, which will face stiff competition from a slew of new and old plants in China, trading sources said.
Asian oil product demand is expected to contract by about 4.3 million b/d and 3.7 million b/d year-on-year in first and second quarter, respectively, according to IHS Markit estimates. OPIS is a unit of IHS Markit.
“Recovery will be gradual amid change in consumption patterns and fears over a second wave of infections. Regional oil demand is not expected to recover to 2019 levels on a quarterly basis through second quarter 2021,” Das said.
The demand recovery is patchy and in some instances such as in Victoria state in Australia, the Philippines, Vietnam and India it has taken a step back as new lockdown measures were introduced at local levels to stop the COVID-19 spread, according to latest consumption data.
Consequently, refiners have turned down runs while others have closed units for maintenance with a few running their numbers internally to work out the long-term future of the sites as was the case with Pilipinas Shell.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Asia gasoline is set to slump with the benchmark Singapore 92 RON crack, or refining margin, on the verge of turning negative in the face of rising supply and demand recovery losing its momentum amid new coronavirus disease 2019 (COVID-19) cases and floods in India and China, traders said.
The 92 RON crack spread fell to $0.563/bbl on Thursday, the lowest since June 4, according to OPIS data.
This margin crashed to minus $12.986/bbl on April 14, the lowest on OPIS records going back to July 2014 as authorities took lockdown measures to contain COVID-19, dampening demand for the transportation fuel. Consumption recovered slowly as these preventive measures were eased on signs of the pandemic slowing.
But COVID-19 spread again, prompting some authorities to reinstate lockdown measures and hindering recovery in gasoline consumption.
To deal with this weakening local demand, some countries, especially China, increased exports, which exacerbated the oversupply in Asia, traders said.
"It is inevitable since the supply glut has not eased," said a Singapore-based trader, when asked if the 92 RON crack will fall below zero.
Some refiners cut runs or shut plants for turnaround, but that may not be enough since demand in Asia lost steam, he added.
In China, Sinopec has lowered operating ratios at some refineries as their inventories jumped due to the recent flood, trading sources said.
The country's largest refiner slashed rates at its 170,000 b/d Wuhan facility to as low as 126,000 b/d in mid-July, according to the sources. It also lowered runs at the 160,000 b/d Hubei and 180,000 b/d Anhui sites, the sources added, declining to provide further details.
Sinopec officials were not available for comment.
Traders booked three tankers so far to lift 155,000 mt for August, after chartering 15 vessels to pick up 680,000 mt in July, according to shipping fixtures. The list also showed one tanker was booked to load 35,000 mt of gasoline and gasoil each in July and August.
A total of 12 tankers were chartered to lift 420,000 mt of in June, the fixtures showed.
In India, where authorities have re-imposed lockdown measures, Reliance Industries Ltd (RIL) and Indian Oil Corp (IOC) will shut crude distillation units (CDUs) for maintenance works, as reported earlier.
RIL brought forward the turnaround of a 380,000 b/d CDU at the export-oriented 705,200 b/d Jamnagar refinery to this week from the initial schedule of Oct. 15, according to sources. The works were expected to finish in three to four weeks.
Those overhauls and lower runs at other refineries may limit Indian gasoline exports, a trader with an Indian refiner said.
However, demand in Asia is weakening again, keeping inventories at high, traders said.
"We had hoped that demand in some countries such as Vietnam, but that didn't materialize," said a Seoul-based trader. Vietnam is also facing a fresh outbreak of COVID-19.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report. Try it free for 21 days
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Sinopec, China's biggest refiner, plans to double gasoil exports to at least 800,000 mt in August from July, adding to an already bulging Asian market as weaker domestic demand pushed them to look overseas, according to market sources.
"It should not come as a surprise given that Sinopec restarted two of its biggest refineries recently," a trader with knowledge of the Chinese market said.
China exported 1.45 million mt and 1.04 million mt of gasoil in May and June, respectively, according to data from the General Administration of Customs (GAC). Shipments in July are expected to rebound to 1.2 million mt, market sources estimate.
Sinopec restarted its 460,000 b/d Zhenhai Refining & Chemical Co. site after about a four-month maintenance and its 250,000 b/d Tianjin facility after a two-month turnaround, as reported previously.
Chinese refiners went on an extensive bargain hunt in spring when crude prices sank to as low as under $20/bbl for ICE Brent, which ended up in record shipments in the summer that is likely to be extended to the autumn, trading sources said.
The world's largest crude importer took in an eye-watering 53.18 million mt, or about 12.9 million b/d, in June, easily bypassing the previous record 11.3 million b/d that landed in May, according to GAC data.
"Chinese refiners probably saw a good opportunity from the slump in oil prices and expectations that the domestic economy will recover after the imposed coronavirus disease 2019 (COVID-19) lockdowns were lifted," a trade analyst said.
However, matters took an abrupt turn when the COVID-19 cases resurfaced, followed by recent flooding in various parts of China which dragged on the economic recovery and curbed oil product demand.
The market is feeling the weight of slower regional demand since early July when resurgence of COVID-19 cases were reported in pockets of the region. The front-month time-spread in the first half of July averaged at $0.51/bbl in backwardation, but shrank significantly to $0.07/bbl in the second half, according to OPIS data.
In a bid to offload inventories from brimming tanks, Chinese players have also resorted to offering steep discounts.
"The most recent 10 ppm gasoil cargo FOB price from China was heard to be at discounts of $0.40/bbl," a trader said. "Pretty steep compared to North Asia's FOB cargoes at around discounts of $0.05/bbl," he added.
Additionally, cargoes loaded from the Middle East and India are also expected to move into Asia if arbitrage economies work in the face of limited buying in the West, market sources said.
In the second half of July, at least 1.02 million mt of ultra-low sulfur diesel (ULSD) due to be loaded from the Middle East and India have East/West options.
That compares with a trickle of rare 35,000-90,000 mt for such arrangements per month in 2018 and 2019, shipping fixtures data show.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report. Try it free for 21 days
--Reporting by John Koh, John.Koh@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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U.S. refined product output capacity that has been chasing significantly weaker demand since April due to the economic fallout of coronavirus disease 2019 (COVID-19) is about to lose another refinery to temporary shutdown, market sources report.
Calcasieu Refining in Lake Charles, La., is expected to shut at the end of July for at least a month and perhaps longer, multiple market sources told OPIS.
Some sources who lift product from the plant -- which can process as much as 137,000 bbl of crude oil per stream day -- were informed of the move in recent weeks.
Another market participant, citing a published report, attributed the idling to low product demand and suggested that restart of the plant would depend on an increase in that demand.
OPIS reached out to a Calcasieu Refining spokesperson regarding plans for the facility, but the spokesperson had not responded to OPIS' queries by presstime.
When operating at or near full capacity, the Calcasieu refinery supplies a considerable amount of heavy naphtha and low-sulfur vacuum gasoil (LSVGO) into the U.S. Gulf Coast spot market. Figures from the U.S. Energy Information Administration show the refinery as having 36,000 b/d of vacuum distillation capacity (hence the VGO output) but nothing in the way of fluid catalytic cracking (FCC) capacity or catalytic reforming capacity.
VGO serves as feedstock for gasoline-making FCC units, and heavy naphtha serves as feedstock for reformers to produce high-octane reformate for gasoline blending.
A testament to the Calcasieu refinery's length on intermediate feedstocks is the fact that Calcasieu-quality LSVGO and Calcasieu-quality heavy naphtha were both seen on offer in the U.S. Gulf Coast spot market last week.
Other U.S. refineries shelved during the pandemic are Marathon Petroleum's 166,000-b/d plant in Martinez, Calif., and its 28,000-b/d refinery in Gallup, N.M. (both in April). As reported by OPIS on June 16, restart of at least the Martinez refinery is not likely in 2020, according to some large unbranded wholesale customers who were privately informed by company sales executives.
Another U.S. refinery -- HollyFrontier's 52,000-b/d refinery in Cheyenne, Wyo. -- is also soon to exit the petroleum-processing business. As previously reported, the refinery is expected to halt refining operations by Aug. 1 in order to begin the process of converting the facility to renewable diesel production by the first quarter of 2022.
The outlook for U.S. petroleum fuel demand, while recovering somewhat from months of decimation by pandemic-spurred lockdowns and stay-at-home orders, remains uncertain.
Weekly growth in gasoline demand, as measured by the OPIS Demand Report survey of sales at more than 15,000 service stations across the country, has stalled at about 1%, and year-on-year deficits have held to a range of 15% to 19% since mid-June.
U.S. diesel demand has been inconsistent. The Energy Information Administration reported demand for the week ended July 17 as 24% lower compared to the same week last year and off by 9.8% on a four-week average basis. Consumption of jet fuel is still faltering compared to a year ago, only recently narrowing its year-on-year deficit to less than 50% on a four-week average basis.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Brad Addington, baddington@opisnet.com; and Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Remember Tier 3 sulfur regulations and the threat of the impact that adhering to tougher 2020 standards might have on refiners, importers and blenders?
Many of those concerns have faded inversely with rising coronavirus disease 2019 (COVID-19) numbers, but an assessment issued this month by the Environmental Protection Agency suggests there is still cause for concern. EPA released its tabulation for sulfur compliance in 2019, and the data showed that the average sulfur level in gasoline last year was still a relatively hefty 17.5 parts per million. That is down just 3 ppm from the 2018 assessment, and some 75% above the actual requirement of 10 ppm for 2020.
Refiners can make gasoline with a sulfur level as high as 80 ppm, but 2020 regulations mandate that they must average 10 ppm sulfur or offset the non-compliance by purchasing expensive sulfur credits. Those credits fetched prices of $3,100 each when OPIS last wrote about the issue in February. A single credit translates into 1 ppm sulfur reduction on 1 million gallons of gasoline, so at $3,100, an importer of a 50-ppm foreign cargo faced a daunting additional cost of 12.8cts/gal back in February.
But despite the EPA's recent measurement of refiners behind the curve in 2019, counterparties in the sulfur credit trading arena have let those compliance instruments slip in value. The drops are attributable to the demand destruction that has changed the dynamic for gasoline supply balances and octane differentials across the country.
Late word had sulfur credits most recently trading between $800 and $1,000 in a very illiquid market. At that rate, a 50-ppm off-spec cargo of foreign gasoline would require credit purchases that would add less than a nickel to the price.
Lower refinery utilization and the COVID-inspired drop in U.S. demand have also dismissed octane worries for the moment. The best means of addressing tough Tier 3 sulfur standards this year would have required running catalytic reformers at very high rates, and that might have limited output of high- octane components. But the lowest refinery runs of the 21st century have left plenty of spare capacity in refining complexes and kept octane spreads in check.
Still, it would be helpful if there was some contemporary discovery on how refiners might be complying with Tier 3 regulations so far in 2020. Sulfur credits were cheap in 2019 and gasoline manufacturers might have relied on purchasing credits and mixing in higher-sulfur hydrocarbons that offered better economics. There's another working theory that holds that most operators can match or exceed the 10-ppm threshold this year.
In the interplay between components of gasoline, credit values and changing specifications, there is one other very observable trend: traders of RBOB are not willing to bet on price plunges that match historical drops tied to the higher RVP specifications that arrive in September.
In 2018, for example, RBOB futures values lost 75cts/gal between final September settlements and late November. Other years have commonly seen drops of 20-40cts/gal tied to the easier task of manufacturing high-RVP winter gasoline.
This year may be different. Butane prices are not as cheap relative to gasoline as in prior years, so loading up motor fuel molecules with cheap high-octane normal butane doesn't look as lucrative.
And there is still the matter of sulfur compliance with naphtha and other components that are well beyond 10-ppm sulfur content. Most of the naphtha that has been available in the North Atlantic in recent years has ranged from 10 ppm to 50 ppm, and blenders may struggle more than in any previous year to make on-spec gasoline.
But the biggest question mark is likely to be gasoline demand. Coming in to 2020, most predictions called for annual demand of about 9.3 million b/d, which would essentially match consumption trends witnessed in 2017, 2018 and 2019.
Most recent EIA reports suggest annual gasoline demand of less than 7.9 million b/d, or a drop of 15% from last year. OPIS demand assessments suggest that the drops have been understated, and are more severe, and a consensus view has formed which holds that "normal" demand won't return until COVID-19 vaccines are available.
If that consensus is accurate, refiners could well run at about 75% of capacity through year's end, with plenty of additional capacity for crude units, reformers and cat crackers.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Pirate attacks on shipping have increased this year as the number of vessels chartered to store oil while anchored offshore has soared following a demand slump due to the spreading coronavirus disease 2019 (COVID-19) pandemic, according to the Allianz Group.
Incidents of piracy reported to the International Maritime Bureau (IMB) totalled 47 in the first three months of 2020, up from 38 in the same period last year,global insurance carrier Allianz Global Corporate and Specialty
(AGCS) said Wednesday in its Safety and Shipping Review 2020. Most pirate attacks targeted oil tankers, but included container ships and bulk carriers, the report said.
In a bid to curb the spreading COVID-19 pandemic earlier this year, governments restricted population movement. The resulting economic slump and declining oil demand prompted the funnelling of crude and refined products into onshore storage facilities. As these tank farms rapidly filled up, there was a surge in the number of tankers chartered for storing excess volumes of oil. Many such tankers were anchored off the coast of major oil ports in West Africa, the U.S. and Europe, with the Gulf of Guinea becoming a hotspot for pirate attacks, according to the AGCS report.
"Piracy remains an ongoing issue. We thought we had a handle on it but it has manifested yet again," said global head of Marine Risk Consulting at AGCS Captain Rahul Khanna in the report. "Incidents have been increasing in West Africa and parts of Asia, where we see a worrying pattern of violent attacks against crew, as well as kidnappings."
Crude oil held in floating storage, on laden ships not moving for more than 14 days, peaked mid-June at some 194 million bbl, before dropping to below 140 million by the end of June, according to data from IHS Markit's Commodities at Sea (CAS) 7 July. A very large crude carrier, typically the largest crude tanker most frequently chartered, can hold 2 million bbl of crude. Floating storage of refined oil products hit a high of around 80 million bbl in mid-May, and then eased to 57 million bbl by 15 July, CAS data showed.
The Gulf of Guinea region, which borders some 3,700 miles of the coastline of West Africa, accounted for 90% of global kidnappings reported at sea in 2019, with the number of crew taken increasing by more than 50% to 121, according to data from the IMB.
"Piracy is typically local in nature, but it can have a global geopolitical impact," said AGCS senior marine risk consultant Captain Andrew Kinsey.
TRACKING COMMODITY CARGOES HAS NEVER BEEN EASIER.
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--Reporting by Rob Sheridan, rob.sheridan@ihsmarkit.com;
--Editing by Tom Sosnowski, thomas.sosnowski@ihsmarkit.com
Copyright, Oil Price Information Service
This was supposed to be the first full driving season where E15 might flourish, thanks to the Environmental Protection Agency's decision to approve the year-round sale of 15% ethanol blends.
But coronavirus disease 2019 (COVID-19) and incredibly cheap gasoline prices intervened. For a substantial portion of May and June, markets often saw wholesale prices for ethanol that were 30-60cts/gal above the price of conventional blendstock (CBOB). Even a rally in prices for 2020 D6 ethanol Renewable Identification Numbers (RINs) wasn't enough to motivate many retailers to offer E15 at the pumps earlier this driving season.
Those economics appear ready to change. Ethanol in bulk markets like Chicago and delivered destinations like Florida and New York Harbor is still far more expensive than CBOB, but futures trading points to different economics next month.
July still finds Chicago ethanol prices just shy of $1.50/gal, or about 25-30cts/gal above gasoline blendstock values. But August futures for ethanol traded Wednesday morning for as little as $1.14/gal, slipping below the price of CBOB in the Chicago market. The action in futures markets is very thin, but if the relationships persist, there could be a substantial move to market E15 at numbers well under the standard E10.
Blending an E10 with $1.16/gal blendstock and $1.14/gal ethanol results in an initial value of $1.158/gal, and with RINs at 47cts, the net price of the finished blend works out to $1.111/gal.
If cheap ethanol futures come to pass in the actual wet markets, the economics for E15 improve substantially. The higher-level blend of 85% hydrocarbon at $1.16/gal and $1.14/gal ethanol results in an initial value of $1.157/gal, but the generation of more RINs results in a deduction of 7.05cts/gal. The outright net price of the finished E15 blend works out to $1.087/gal.
Some blenders are skeptical that cheap forward ethanol numbers will slip below the value of gasoline blendstocks. The last time Chicago CBOB was cheaper than ethanol was March 5, 2020. That was a few weeks before COVID-19 lockdowns and subsequent demand destruction eventually lopped more than $1.20/gal off the value of conventional blendstock. CBOB eventually traded at just 21.5cts/gal on April 7, or about one-fourth of the price of ethanol at the time.
Get accurate, up-to-the minute news, pricing and analysis for buying and supplying ethanol-blended fuel and biodiesel with OPIS Ethanol & Biodiesel Information Service. This service includes real-time news alerts, end-of-day pricing assessments, and a weekly newsletter and rack pricing report. Sign up now for a free 3-week trial now!
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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There was a time when hurricanes were the biggest disrupters to U.S. refining operations, but the coronavirus disease 2019 (COVID-19) pandemic has changed that.
U.S. refinery utilization has averaged less than 83% of capacity for 15 weeks, including a number of plants at minimum rates or idled (Marathon Petroleum's refineries in Martinez, Calif., and Gallup, N.M).
That degree of slackness is more comparable to late 2009 into early 2010 (25 weeks), when the Great Recession was driving a shakeout in the industry, than to the seven weeks of widespread downtime in the U.S. Gulf Coast due to 2017's Hurricane Harvey.
Petroleum fuel demand decimated for months by pandemic-spurred shutdowns and stay-at-home orders has recovered somewhat, providing rays of hope for financially battered refiners looking to hike production. But the operational landscape remains dotted with potholes, according to downstream analysts.
Factors now in play for refiners include demand for gasoline that continues to trail a year ago and is showing little to no weekly improvement; still badly faltering consumption of diesel and jet fuel; strong to record-high inventories of gasoline and diesel; a patchwork of changing state government measures to contain COVID-19; and - perhaps most disruptive of all - uncertainty through at least end-2020.
When it comes to refining forecasts, two questions are paramount for Debnil Choudhury, head of North American refining at IHS Markit. If COVID-19 infections can at least stabilize in the short term without new shutdowns will demand get back to a pre-virus level? And in the event of new containment action - such as California's rollback this week - will demand fall back to the lows of March and April?
IHS Markit is the parent company of OPIS.
Choudhury and others stress that refiners have done their best to reduce production and inventories.
Early on, when gasoline and jet demand fell more precipitously than diesel, refiners "shifted gas oil upgrading from gasoline-centric FCC [fluid catalytic cracking] units to diesel-centric hydrocrackers," said John Auers, executive vice president of Dallas-based energy consultancy Turner, Mason & Co. At the same time, refiners blended kerosene into diesel instead of into jet, he added.
However, the highly uneven nature of fuel demand recovery has proven to be very challenging for refiners.
Gasoline demand has been recovering for weeks, spurring optimism among refiners, only recently stalling at 10% to 15% below year-ago levels. Diesel demand is now looking better, lagging a year ago by about 6.5% and jet fuel demand is off by 52% year on year. Some gas oil upgrading has been shifted back to FCCs to increase gasoline yield as demand has risen, but the effect of raising crude throughputs at refineries has also swelled diesel inventories.
"That has to be dealt with," Andy Lipow, president of Lipow Oil Associates in Houston, told OPIS. "Gasoline margins could improve or even spike, but at the same time they would be offset by margin deterioration in jet and diesel," he said, suggesting that upward pressure on diesel inventories could widen ULSD market contango enough to incentivize putting the product into floating storage.
Choudhury is also concerned about building stocks of distillate and noted that refiners have taken a different tack in recent weeks. Processors have been shifting diesel yield toward jet fuel yield "even through there's almost no improvement in jet demand because there is more room to store jet fuel," he said. IHS Markit tracking has shown jet fuel yield rising and diesel yield falling, along with increasing gasoline yield, he noted.
A look at U.S. stocks since demand began softening in April shows a net increase of 54.1 million bbl, to 176.8 million bbl, according to weekly data from the U.S. Energy Information Administration. As recently as the week ended July 3, total diesel inventories were at their highest level since early 1983.
Over the same period, U.S. jet fuel stocks have risen by a net 1.5 million bbl to 40.4 million, well below the highest level seen in the last five years, 47.4 million bbl in early October 2018. Meanwhile, total gasoline stocks have fallen by nearly 8.8 million bbl to 248.5 million since early April.
Choudhury advises refiner restraint until diesel and jet inventories come down to more normal levels. "If refiners chase gasoline now they risk having an even bigger diesel oversupply," he told OPIS.
With many U.S. refiners depending on refined product exports for placement of production since about 2008, those companies should be closely following market fundamentals in Europe and Latin America for diesel, and fundamentals primarily in Latin America for gasoline, Choudhury added.
The latest weekly EIA data depict distillate exports steady at 1.332 million b/d, but still lower than levels seen before COVID-19. Before mid-April, weekly 2020 estimates of exported distillate at times had exceeded 1.4 million and 1.5 million b/d.
Estimated weekly departures of U.S. gasoline only just passed the 600,000 b/d mark last week - a level that was commonly exceeded by as much as 200,000 b/d in 2020 until the end of April. In May and June, estimated weekly gasoline exports averaged 332,000 b/d.
Amid a recent spate of processing unit restarts following idling, reduced runs and some planned maintenance, the analysts question refiners' ability to increase throughputs at their plants.
For Choudhury, even if U.S. gasoline demand can surpass and hold above 9 million b/d, demand for diesel and jet fuel aren't likely keep pace given consumers' reluctance to fly and COVID-19-damaged international trade which has slowed truck transportation of goods across the U.S.
"There's going to be some room for refineries to run but it will be hard to come back to pre-virus levels," he said. That could be as long as it takes for there to be a vaccine for COVID-19, which might not be until the second half of next year.
Lipow is also focused on vaccines, seeing development of a proven vaccine against COVID-19 as the single greatest influence on U.S. consumer behavior and fuel consumption.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Steve Cronin, scronin@opisnet.com
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The outbound flow of diesel cargoes loading from India has tilted increasingly eastward since the outbreak of the coronavirus disease 2019 (COVID-19) pandemic earlier this year, with fewer shipments heading West of Suez, according to IHS Markit's Commodities at Sea data.
Over 40% of diesel cargoes tracked loading from India's ports of Sikka, New Mangalore and Vadinar discharged into southeast Asian terminals in June, while northwest European ports took little more than 5% of the total flow. This marks a reversal from June 2019, when around 30% of diesel shipments which loaded from the west coast of India unloaded at northwest European ports, with no diesel cargoes tracked discharging in southeast Asia, Commodities at Sea data showed.
The eastward switch tracked in diesel cargo flow from India began most significantly in April and continued throughout the quarter, peaking in June.
April flows to southeast Asia this year accounted for some 20% of Indian diesel exports, compared with 15% in April 2019.
The majority of diesel tracked loading from ports along the west coast of India initially flowed into the key regional storage tank farms in Malaysia and Singapore, but cargoes are also making their way into the spot market as demand begins to pick up across the region, according to IHS Markit analysts.
Asian diesel demand recovery has outpaced that of supply by about 500,000 b/d, which facilitates the depletion of accumulated inventories in the region, according to IHS Markit consulting associate director Hedi Grati. In turn, this allows India's exporters to place their surplus, said Grati.
"Asia is recovering faster than Europe, as many Asian economies have been more targeted at setting up their response strategy to the coronavirus disease compared with Europe, and demand for ground transportation fuel returns to a more decent shape," said Grati. "Given the massive oversupply of product in Europe, partly due to jet minimization efforts, it's understandable why Eastbound exports would be prioritized."
Transportation mobility was back to January levels in many Asian economies by early July, and up considerably from April and May, according to the International Energy Agency in its July Oil Market Report, in which it cited Google data.
In OECD Europe, transport fuel demand is still much lower than the level a year ago. In May, oil product demand is estimated to have risen 770,000 b/d month on month but remained 3.1 million b/d below its year-ago level, according to the IEA. Mobility remains below seasonal norms everywhere especially in the UK, which lags behind the rest of Europe after the U.K. government applied confinement measures later than most other countries.
"European countries applied some of the strictest containment measures in the world with the vast majority of the continent's citizens told to stay home during the month," said the IEA in the July report. "The decline in fuels demand reflected the region's product mix and was therefore more weighed towards gasoil/diesel than gasoline."
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--Reporting by Rob Sheridan, rob.sheridan@ihsmarkit.com;
--Editing by Karen Tang, karen.tang@ihsmarkit.com
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Flaring occurred Tuesday at the Shell-operated 404,000-b/d Pernis refinery near Rotterdam in the Netherlands, according to eyewitnesses, with market sources saying Europe's largest plant is becoming fully operational after a turnaround.
Two eyewitnesses, one of whom is an oil trader, said that flaring at the refinery was visible early in the morning local time.
The trader had previously suggested that some units at Pernis, including those maximising the refinery's middle distillates production, would not be operational until the middle of July, even though other units came back online last month.
The turnaround at Pernis that began in mid-April lasted longer than Shell had previously anticipated, owing to the deployment of social-distancing measures.
The loss of production offered support to northwest European refining margins at a time of oversupply when demand for products slumped as governments enforced lockdowns to combat the coronavirus disease 2019 (COVID-19) pandemic.
The northwest European diesel crack, an approximate measure of refining profitability, hit a low of $0.27/bbl on 7 May. Jet cracks plunged to minus $8.88/bbl on 5 May. The diesel crack has since crept higher due to returning demand to $5.82/bbl as of Monday, while the jet crack was pegged at $1.62/bbl, according to OPIS data.
A spokesperson for Shell was not available for comment when contacted by OPIS.
Gain greater perspective on global spot prices for naphtha, propane and butane.
OPIS developed the pricing in our Europe LPG & Naphtha Report to reflect the market’s desire for an unbiased methodology and accurate spot price benchmark in northwest Europe and the Mediterranean.
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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China imported record crude oil volumes in June as savvy traders took full advantage of sagging prices back in March and April to ramp up purchases that could potentially lead to another all-time high in July before tapering later in the third quarter, trading sources said.
The world’s largest crude importer took in an eye-watering 53.18 million mt, or about 12.9 million b/d, in June, easily bypassing the previous record 11.3 million b/d that landed in May, according to preliminary data from the General Administration of Customs (GAC).
ICE Brent crude, which started trading at the start of the year at just under $70/bbl saw the bottom fall out in March when the OPEC+ producer group failed to agree on an output cut. Brent tumbled to a low of $22.71/bbl in end-March after Saudi Arabia and other Middle East producers opened their oil taps and slashed prices.
It went below $20/bbl in late-April as the coronavirus disease 2019 (COVID-19) spread across the globe and decimated fuel demand, leading to record consumption drops of as much as 18 million b/d at its height in the second quarter. Prices have since recovered to around the $40/bbl mark following a new OPEC+ output cut pact and budding oil demand recovery.
“The Chinese buyers bought a lot of spot barrels when oil was cheap. This is within market expectation, in fact July might even be higher as the port congestion eases and long haul cargoes arrive,” said one trading source.
“Imports will drop in the third quarter as the margins for tea pots are down but we will see a pickup maybe in October or November. This increase does help balance off the cuts made by Saudi Aramco and other Middle East term suppliers,” he added, pointing to the allocation cuts made by these producers in compliance of their OPEC+ accord.
“This is pretty much in line with our earlier expectation, it is mostly economics driven and imports from all regions saw a material jump in June. We expect this will continue at least into July as most July-arriving cargoes were also purchased when prices were relatively low,” said Feng Xiaonan, IHS Markit downstream analyst in Beijing.
The purchases well exceed Chinese refinery runs, especially in the second quarter when the nation was in the grip of COVID-19, leading most participants to agree that a lot of the oil has gone into storage, the capacity of which many had underestimated, according to Feng.
China would have built up a record 440 million barrels of crude oil inventories in the first half of this year, according to an IHS Markit research released on June 15. The peak of the stock build, on a daily average basis, was 4.8 million b/d in February when local oil demand was at a low point due to COVID-19, it said.
"China will have to de-stock in one way or another as it simply cannot have unlimited storage capacity to hold that much crude," Feng, who was also one of the authors of the analysis, said at that time.
Data from IHS Markit’s Commodities At Sea (CAS) ship tracker shows a step increase in Chinese global crude oil purchases for loading in April that was largely sustained in May and June.
China Global Seaborne Crude Oil Imports
China cranked up spot purchases as oil prices tumbled, raising April loadings to 12.3 million b/d from 7.4 million b/d in March with 1.1 million b/d of the April cargoes yet to arrive, according to the CAS data.
Of the 12 million b/d bought for loading in May, 3.1 million b/d has yet to make land, with 7.3 million b/d of 10.8 million b/d of June liftings also still on the waters, the CAS data showed. All 9.2 million b/d of July cargoes that were picked have yet to reach China.
These numbers point to another bumper delivery month in July, trading sources said.
The increase does go some way towards mitigating the sharp falls in shipments from the Middle East, especially Saudi Arabia as the kingdom lived up to its end of the OPEC+ output reduction accord by deep cuts to its May, June and July exports, they said.
However, shipments are set to grow in August as initial term allocations point to Asian refiners getting their full volumes should they request for it, however, one or two sources add that not all buyers are getting everything they asked for.
“I am hearing of cuts to Arab Heavy and Arab Medium with Saudi Aramco offering Arab Light instead,” one trading source said.
The customs data showed that Chinese refiners refrained from entering the oil product export market in full force amid better domestic margins, due to a local retail floor price at the equivalent of $40/bbl crude, and cut throat overseas pricing amid a supply glut.
Fuel exports in June slumped to a 16-month low of 3.87 million mt from 3.89 million mt in May, the GAC data showed, without providing a breakdown of the products. Shipments jumped to a record 8 million mt in April.
However, shipments have picked in July as seen in recent shipping fixture reports but are still well short of typical levels due to COVID-19, which may lead to reduced refinery runs resulting in a longer period of lower imports, trading sources said.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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If you operated fuel sites in the United States during the three days preceding July 4 this year, that period may very well represent the peak of this driving season unless coronavirus disease 2019 (COVID-19) suddenly disappears.
Marketers interviewed by OPIS this week are acknowledging an alarming midsummer slide in sales this week, and preliminary data suggests that demand reports may show numbers last witnessed in May.
The slide in consumption actually started on Independence Day and is hardly unprecedented since most consumers have reached their destinations and don't tend to travel far on the Fourth of July holiday. But even before that slide, some states impacted by rising COVID-19 cases were beginning to trend lower.
OPIS Demand data for Florida, for example, showed a 6.9% decline from the week ending July 4, versus the week ending June 27. The week ending July 4 saw total U.S. demand virtually match the week ending June 26, with notable increases in some Mid-Continent states bucking the overall flat trend.
This week has brought substantial change, however.
Consider that individual retail chains saw gasoline sales climb to 95% or more of the same period last year for the days preceding the July Fourth holiday.
States such as Illinois, Minnesota, North Carolina and Ohio even saw some year-on-year increases in sales.
But the most recent seven days have brought the most dramatic backslide in gasoline since the late March lockdowns. One fuel supply executive with hundreds of sites acknowledged that this week has been "absolutely dismal" for gasoline sales, particularly in Southern states that have seen COVID-19 cases rise, thanks in part to fears stoked by stories about the pandemic leading off most nightly newscasts.
Outright demand numbers for the entire week will be gathered by OPIS in the coming days, but some states have seen percentage losses from 2019 double or even triple in the last seven days.
Alabama, for example, had staged a steady recovery to nearly 90% of 2019 volumes, but sales this week are closer to 75% of normal. Arizona, which is seeing COVID-19 cases rise at a rate higher than any foreign country, was back to about 90%-93% of normal before July 4. More recently, sales are at about 85% or less than the same period last year.
The COVID-19 impact has reared its head in other Southern and Western states.
The state with the greatest consumption of gasoline -- California -- saw pre-holiday fill-ups that brought sales up to about 83% of normal. Thanks largely to new restrictions, and fear of visiting crowded venues, this week finds the Golden State losing more than 20% of year-ago volumes.
Florida continues to deteriorate after being a bright spot or perhaps more accurately an "anomaly" for small and large retailers. In June, despite the rampant COVID-19 headlines, the rate of demand destruction descended to 5% to 10%. In some counties, the last seven days have seen that rate of attrition triple.
Texas might have a deserved reputation for risk-taking, but rising COVID-19 case clusters in Houston, Austin and Dallas have really hurt recent demand.
Chains flirted with 90% of normal sales in that last week of June, but the decline from same week last year has accelerated to more than 20% in recent days.
These are all fresh numbers, and while they represent actual data for year-on-year pump sales, a measurement of fuel dispensed doesn't quite catch the fancy of the investment community. Recent weeks have seen some investment banks champion high-tech oracles, whether it be Apple Mobility, Tom-Tom or other GPS-based technology that attempts to track consumer movement. Based on initial data received by OPIS for pump sales, however, those tools may be poor measurements of actual fuel use.
And then there is the Energy Information Administration. EIA has the thankless task of releasing an "implied demand" number every Wednesday that can certainly impact those who trade RBOB and other petroleum contracts.
But EIA has always been honest about the flaws of "implied demand" and has consistently stressed that it does not measure gasoline sales. It simply looks at inventory changes, production, imports and exports, and comes up with a "product supplied" number that can often represent product moving from reportable (bulk terminals) to non-reportable (station tanks) storage.
OPIS has observed that the EIA "product supplied" number can be skewed by trading strategies, or by a rush to fill up stations ahead of predictable increases. Price volatility can manifest itself in massive "dispatch or delay" strategies from thousands of marketers and dramatically alter EIA assessments.
Based on data and interviews with large multistate marketers this week, OPIS suspects that real demand may be back to around 80% of normal.
Accordingly, that suggests the second EIA gasoline demand number of July 2019 may set the industry up for a very disappointing Weekly Statistical Bulletin next Wednesday. The gasoline demand reading in that slot last year was just 9.214 million b/d, by far the poorest measurement in June, July or August. If this year's assessment comes in at 80% of that number, we are looking at a demand reading of less than 7.4 million b/d.
For gasoline bulls, you have been warned.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Asian petrochemical makers plan to use more liquefied petroleum gas (LPG) in August for a second straight month as gas cracking economics improved following a jump in naphtha prices due to strong downstream and gasoline demand.
Naphtha consumption, however, is also expected to increase in the coming months as steam crackers return from scheduled turnaround, analysts said.
Cracker operators that are able to use naphtha and LPG will intake 438,000 mt of the gas in August, up 7.6% from a revised 407,000 mt this month, an OPIS survey that concluded on July 8 showed.
The petrochemical manufacturers had planned to crack 310,000 mt in July, according to the previous poll published on June 5. They used 306,000 mt in June.
Favorable economies of propane and butane over light naphtha prompted Northeast Asian cracker operators to buy more LPG at discounted prices to naphtha.
The propane/naphtha ratio was assessed at 76.7% on Monday, the lowest since Feb. 13, according to OPIS data. The ratio on April 15 jumped to 179.3%, the highest on the data.
Petrochemical producers typically find it more attractive to crack naphtha instead of LPG when the ratio rises above 90%.
Hanwha Total Petrochemical Corp. (HTC) bought one 22:22 lot for end-July delivery to Daesan via a tender with propane at a single-digit discount to the Far East quotes and butane at a discount of $30s/mt to the Japan naphtha quotes, according to sources.
The producer subsequently issued another tender seeking an additional 23,000 mt propane lot for 2H August delivery.
A South Korean trader issued two term buy tenders for 23,000 mt butane per month for delivery to Yeosu over three or six month starting from September or October.
The prompt month CP for butane is at a double-digit discount to propane since early June on the back of weaker cooking fuel demand in India.
"I don't think naphtha demand will be substantially reduced by LPG cracking.
There will be more crackers coming back on stream from turnarounds in August and it should support naphtha demand," said April Tan, IHS Markit associate director in Singapore, adding that there's a 20% limit on the use LPG as cracker feed.
Light naphtha demand in August will increase to 3.58 million b/d from 3.364 million b/d in July, Tan said.
Mitsubishi Chemical, Maruzen Petrochemical and Mitsui Chemicals are on track to restart their crackers over the next two weeks after completing scheduled maintenance works, as reported earlier.
Mitsubishi Chemical will crank-up its 539,000 mt/year plant in Kashima this week, while Maruzen Petrochemical will resume its 525,000 mt/year unit in Ichihara next week. Mitsui is also on track to complete maintenance at the 500,000 mt/year Osaka facility on July 20.
Asian naphtha markets strengthened with the CFR Japan price on Monday reaching a four-month high of $406.500/mt, according to OPIS data, supported by healthy petrochemical demand, tight supply and increased gasoline consumption following relaxations of lockdowns over the coronavirus disease 2019 (COVID-19).
By contrast, LPG prices lost ground as the surge in buying for use as cooking fuel during the lockdown led high inventory builds amid the seasonal summer lull in the northern hemisphere. CFR Japan LPG on June 29 fell to a one-month low of $328.00/mt, OPIS data showed.
Ethylene production costs and margins from LPG were better than naphtha, according to IHS Markit Asia Light Olefins Weekly report published on July 3.
OPIS is a unit of IHS Markit.
The cash cost of steam cracking in Northeast Asia using LPG was estimated at $401/mt on June 25, generating a margin of $404/mt, the report showed. The costs of cracking naphtha was at $517/mt and the margin was $288/mt.
However, LPG cracking economics are expected to deteriorate from September as naphtha prices will ease on higher output, said IHS Markit's Tan.
"The economics of LPG cracking is expected to be less attractive compared to naphtha in September as naphtha prices will moderate with the increase in domestic regional supply to meet demand requirements," she said.
Crude runs in the Middle East and Asia Pacific are expected to slowly recover to 76% in September from 69% in June, Tan added.
Refiners across Asia are gradually increasing operating ratios as easing lockdown measures helped fuel demand and overall economic activity recover.
The Asian Manufacturing PMI, compiled by IHS Markit, rose to 47.4 in June, the highest since March, indicating manufacturing condition is better even though it's not expanding.
Ethylene market sentiment in Asia also held firm on increasing demand and tight supply, while caution emerged given large quantities of U.S.-origin cargoes bound for Northeast Asia, according to the IHS Market report.
A petrochemical company's procurement officer in Northeast Asia agreed.
"In August, we will see a lot of ethylene coming from the U.S. So, ethylene markets will see a peak soon," said the official.
Methodology: OPIS collects Asian petrochemical companies' plans for the current month and the next month, as well as actual cracking volume in the previous month. OPIS, a unit of IHS Markit, checks if any manufacturers revise their plans for the current month and if any manufacturers crack more or less than initial plans in the previous month. OPIS contacts feedstock procurement officers of each companies for the survey by phone, email or messengers in the last week of previous month or the first week of the current month. OPIS surveys 16-20 companies a month.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com, Masayuki Kitano Masayuki.Kitano@ihsmarkit.com, Lujia Wang Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Tighter naphtha supply and recent downturn in clean tanker freight rates have bolstered premiums for FOB India barrels, market sources said.
Supply of all naphtha grades tightened as refiners worldwide operated at below capacity to counter the loss in fuel demand stemming from coronavirus disease 2019 (COVID-19) mobility restrictions. At the same time, resilient petrochemical demand kept Asia cracker run rates at more than 85%, widening the supply shortfall, they said.
Strong fundamentals are evident in the naphtha to Brent crack, or refining margin, which climbed to $94.80/mt on Tuesday, the largest since Feb. 11.
Accompanying the expanding crack was the widening of the front-cycle backwardation to plus $20.50/mt, also the largest since Feb. 11, OPIS data showed.
Indian Oil Corp. (IOC) sold 35,000 mt at a premium of $40/mt to its own formula for July 20-22 loading from Chennai, about double a previous comparable sale for June 17-19 loading, two sources said.
Last week, Hindustan Petroleum Corp. Ltd. (HPCL) sold to Aramco Trading Co. at $33-$34/mt to its own formula 28,000 mt for 20-22 July loading from Vizag, up from the plus $20-$21/mt for a June 19-21 cargo.
A combination of lower arbitrage flows as well as exports from the Middle East and India has bolstered spot premiums not just on the CFR but also on FOB markets, a trade source said.
Arbitrage inflow for August arrival is estimated to be 1.2 million mt to date, said a trade source, compared with the average 1.7-1.8 million mt.
"Market is extremely tight for all grades of naphtha, so FOB just keeps rising," another trade source said.
The recent slump in MR freight rates to Worldscale (WS) 55 for the West Coast India to Chiba route from WS 100 a month ago is supporting the premiums, the first trade source added.
But MR freight rates may be close to bottom because ship owners are making a loss at current rates, said Anoop Jayaraj, clean tanker broker at Fearnleys Singapore, adding that the lump sum at WS 55 for 35,000 mt would be around $429,000, or around $12/mt.
"These rates are historic lows, ship owners' earnings are below $2,000/day, which are unsustainable," Jayaraj said.
The freeing up of tankers from earlier use as floating storage at the start of COVID-19 lockdowns, along with below-capacity refinery utilization, curtailed liquidity in oil product trades and led to the slump in freight, he added.
"TC5, or LR1 rate for AG/Japan 55,000 mt is trading below WS 70 and earnings are around $6,500/day, which is also very low for owners," Jayaraj added.
Ethylene operating rates in July are projected to be 89% for Northeast Asia and 88% for Southeast Asia, according to the latest IHS Markit Asia Light Olefins Weekly Market Report, up from 86% and 87% last month, respectively.
Three naphtha crackers in Japan are on track to resume operations later this month, after the completion of maintenance works, as reported by OPIS.
"Naphtha is extremely tight, but one concern is demand. Cracker margins still look okay but aromatics are a worry," said a trader.
Escalating naphtha prices have eroded olefins margins, said a northeast Asian buyer, adding that substituting naphtha with liquefied petroleum gas (LPG) is one solution but the impact on rising costs is limited because the gas can typically replace only up to 20% of naphtha.
Spot production cash margins for Northeast Asian crackers using naphtha dropped to $288/mt as of June 25, down 17.7% from the preceding week, according to the Asia Light Olefins report.
An additional concern for Asian olefins producers is the anticipated influx of large volumes of deep-sea ethylene from the U.S. this month, another northeast Asian buyer said.
Growing buyer resistance to the naphtha price escalation is seen in the recent withdrawal of H1 and H2 Aug. purchase tenders by Hanwha Total Petrochemical, Yeochun NCC and LG Chem.
"End users all just don't like the offers they have been shown," a trade source said.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Italy's Eni joins fellow majors BP and Royal Dutch Shell in lowering its long-term price assumptions for Brent crude and writing-off asset values through impairment charges amid weak demand for oil and gas due to the coronavirus disease 2019 (COVID-19) pandemic, it said Monday.
The Rome-based company revised its long-term price assumptions for Brent crude oil to $60/bbl from 2023 onwards compared to $70/bbl previously. Brent prices are expected to average $40/bbl, $48/bbl and $55/bbl each year for the period 2020 to 2022. That's compared to previous assumption of annual averages at $45/bbl, $55/bbl and $70/bbl for the same period.
"Our changed long-term assumptions, reached four-months after the outbreak of the COVID-19 pandemic, reflect our current expectations about future prices and will be incorporated in our processes of capital allocation," Claudio Descalzi, Eni chief executive officer, said in the statement.
Eni has made no change to its refining margin assumption in the Mediterranean region at just below $5/bbl over the long-term. It expects to record a non-cash post tax impairment charge in the region of euros 3.5 billion, plus or minus 20% in its second quarter results statement on 30 July, the oil major said.
Similarly, BP is writing off up to $17.5 billion of assets in the second quarter, according to a company statement in June. BP reduced its Brent crude long-term assumption to an annual average of $55/bbl until 2050, down from its previous forecast of $70/bbl, due the increasing likelihood of COVID-19 having an "enduring impact" on the economy and demand, the company said.
Royal Dutch Shell revised its Brent crude assumption to $35/bbl in 2020, $40/bbl in 2021, $50/bbl in 2022, $60/bbl in 2023 and a long-term assumption of $60/bbl in real terms for this year, reflecting the negative effects of the COVID-19 pandemic and the "ongoing challenging commodity price environment", the company said 30 June.
Shell is expecting a post-tax impairment charges in the range of $15-22 billion in the second quarter.
"Eni remains one of the more leveraged names among the integrated [oil majors], and thus we expect to see more material downgrades to estimates given this year's challenges," said Biraj Borkhataria, analyst at RBC Capital Markets in a note on Monday.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Stacy Irish, stacy.irish@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Saudi Aramco, the world's largest crude oil exporter, raised its August official selling price (OSP) to Asian refiners by the most compared with term buyers in the rest of the world, reflecting signs that fuel demand in the region is better than elsewhere, trading sources said.
The producer raised its August OSP to Asia by a uniform $1.00/bbl across the grades from July, keeping the quality spreads unchanged, according to a price list. This compares with changes of a drop by $1.00/bbl to an increase of $0.70/bbl with buyers in the Mediterranean enjoying cuts to three of the four grades.
"It reflects the price structure of the market, Dubai is the strongest of the three benchmarks Aramco uses for its prices," said one trading source, pointing to a modest contango in Brent and WTI whereas Dubai is firmly backwardated.
At the same time, some say that the increase was at the top end of their estimate following Aramco's large $6.10/bbl increase in July for its biggest Arabian Light grade to Asian refiners, while others point out that it was well below the $2-$3/bbl suggested by the Dubai price curve.
One of the kinks arising out of the latest OSP is that unlike in July, which was followed by other Middle Eastern producers, this time some players question if suppliers like Abu Dhabi National Oil Co. (Adnoc) would be able to make like-for-like increases following a narrowing of the Oman/Dubai spread.
"If Adnoc makes the same increase, Upper Zakum will be at a premium of $2.00/bbl to Dubai and that's just crazy," said one trading source, adding that because of the thin Oman/Dubai spread Adnoc would be hard pressed to make a similar increase to that by Aramco.
In Asia, Saudi Aramco sets its crude OSP against a combined Oman and Dubai price. One way of ascertaining the future value of its crude as they are published for the first month out (currently August) is by looking at the forward curves, typically the M1/M3 shape for Dubai swaps and DME Oman.
The shape of this curve strengthened considerably from a month ago on the back of the supply cuts and a resurgence of demand as nations eased their coronavirus disease 2019 (COVID-19) lockdown measures.
Following stronger buying interest for Oman, particularly from independent Chinese refiners enjoying hefty margins due to the $40/bbl crude oil floor price, a big premium developed between Oman and Dubai.
The spread, which averaged around $3.00/bbl in April and May, narrowed to about $1.00/bbl in June, making it tough for Adnoc to follow Aramco's lead as its crude oil for now are priced solely against Dubai, the trading sources said.
The Aramco OSP increase gives refiners in Asia some breathing space and likely ensure that they do not cut back on term nominations, the sources added.
"Most Chinese refiners are price takers as they rely heavily on Middle East crude and will only decrease/increase loadings purposefully if the prices turn out to be too far off from their expectation," said Feng Xiaonan, IHS Markit downstream analyst in Beijing, adding that given the current tight global medium-sour supply, Chinese refiners may take whatever they are allocated to secure their base load.
Global crude oil supply were restricted after the OPEC+ group agreed to extend their output cuts at the deeper 9.7 million b/d level from June to July and have yet to discuss if this would be further extended to August.
One consequence of the cuts was the tightening of medium-sour grades as Russia, one of the biggest participant in the exercise, slashed shipments of its Urals crude significantly, trading sources said.
The smaller increase versus the Dubai price structure is also due to volatile refining margins amid fears of a possible second wave of COVID-19 outbreaks, trading sources said.
"It looks like Aramco did listen to their term buyers this time, the smaller increase means refiners can take their full allocation," one source said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Refiners are processing more so-called dumbbell crudes, a cocktail of very heavy and extra light grades, as part of efforts to limit jet-kerosene production as the bulk of global passenger aircrafts remain grounded, trading sources said.
The cocktail, a mixture of heavies such as Basrah Heavy, Cold Lake and Western Canadian Select and lights including WTI, Eagle Ford as well as condensates, yields more light ends and bottom residues, in the shape of a dumbbell with little middle distillates such as jet fuel.
"Last month, differentials for heavier grades like Basrah Heavy was so strong because of this demand. Refiners were balancing them against all the condensates and light U.S. crude they had bought," said one crude trading source, adding premiums rose to over $5/bbl for June loading compared with the current around $1.50/bbl.
Prices of naphtha and gasoline rose on the back of easing coronavirus disease 2019 (COVID-19) lockdown measures that rekindled road transportation fuel demand, with naphtha buoyed by both stable intake as a petrochemical feedstock and its diversion into the gasoline pool as a blendstock, they said.
At the same time, demand for residues as secondary unit feedstock and for use as marine bunker fuels or in boilers were just as strong, the trading sources said.
The naphtha crack, or refining margin, rose to a four-month high of $83.775/mt on June 24, the largest since February 13, according to OPIS data. It was at $78.45/mt on Tuesday.
On the other hand, jet fuel crack sank deep into the red on several occasion, at times lasting weeks, since the COVID-19 pandemic spread across the globe from March and has not risen above $5/bbl, data from OPIS showed. It slumped to a low of minus $5.53/bbl on May 5.
The aviation fuel, once a darling of the industry as they wagered on strong air travel, is now a bane as refiners sought all options to get rid of this unwanted oil product. Last September, for example, the jet fuel crack soared to above $18/bbl.
"No refiners would even think of this even a few months ago," said Feng Xiaonan, IHS Markit downstream analyst in Beijing, adding that processing such crude cocktails was one of the ways refiners were getting rid of surplus jet fuel.
"The steps to destroy unwanted jet stream is to first blend it into diesel up to the upper limit, blend it into cracker (petrochemical) feedstock, switch to dumbbell-like crude slate...if these are not enough then a refiner may need to lower runs as a last resort," she said.
Ironically, about five years ago on the back of the surge in U.S. shale production an abundance of light-sweet crudes with API gravity in excess of 45 led to their blending with heavier grades to match WTI specifications. However, their dumbbell yield led to concerns over quality as the much sought after jet-kerosene and diesel were minimized.
A huge inflow of light-sweet crude from the U.S. has landed in East Asia, including China, in June with more set to arrive in July and maybe even August, which brought about a resurgence in the demand for heavy grades, trading sources said.
"The crudes coming in were too light for the Chinese system, there was some percentage of sour grades but it wasn't enough," said one trading source, adding that refiners topped up long-haul heavies such as Mars and Cold Lake with more Middle East grades including Basrah Heavy.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Sok Peng Chua, SokPeng.Chua@ihsmarkit.com
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The last time Mont Belvieu non-TET natural gasoline prices were this low, the U.S. and Russia were at odds, Chernobyl was on television, and there was a highly anticipated space shuttle launch.
The year was 1986.
This month, Mont Belvieu non-TET C5 fell to a stunning 34-year low, according to OPIS TimeSeries data. On June 26, natural gasoline trading out of the Enterprise Products Partners storage caverns plunged to 23.25cts/gal. That's a 46% decline since June 22, when the price was an average of 43cts/gal. The last time prices were lower was on Aug. 4, 1986, when C5 averaged 22.5cts/gal.
After a slight drop on June 23, the bottom fell out the next day, to 33.5cts/gal and then down to the current level. Prices have started to recover over the last few trading days of the month. In early trading Tuesday, the range was up to 28-30cts/gal. This may be a signal for an even bigger jump forward once the calendar turns to July.
Prices in the forward months suggest this foray into the red may be only temporary. July barrels of non-TET C5 were fetching 30ct premiums to anys, and August traded at a 19ct/gal contango to July. The OPIS NGL forward curve shows natural gasoline making gains until about October, and then the curve flattens out through the rest of 2021. The curve shows prices peaking just before 80cts/gal.
A source said these contangos should normally be no more than 2-3cts/gal.
Furthermore, TET (Lonestar) and other non-TET (Targa) natural gasoline anys were assessed recently at premiums of 42.5cts/gal to non-TET. Conway natural gasoline prices also remain at a hefty premium to non-TET C5.
There have been reports of operational problems at the Enterprise storage facility, which may be causing some distressed sales. However, there has been no confirmation. Enterprise does not typically provide operational information related to specific assets or market dynamics. Enterprise does not "have any kind of comment or details to share at this time," Rick Rainey, Enterprise's vice president of public relations, told OPIS.
Additionally, Enterprise announced earlier this year that it may repurpose some of its NGL caverns to accommodate refined products. A market source told OPIS that in terms of its chemical composition, natural gasoline is the "most compatible" NGL for that kind of transition.
Petral Consulting's Dan Lippe was not sold on either theory.
"Mont Belvieu does not have the necessary infrastructure and distribution systems in place to accommodate refined products storage," he said. "Until EPD has confirmed on the record that storage in natural gasoline service is being converted to refined products, I will remain very skeptical. The economics that drive natural gasoline prices are based on upgrading the stream octane value ...via pentane/hexane isomerization."
Lippe has surmised that this recent decline was a result of an unexpected slump in demand for natural gasoline from refineries.
"Sometimes isomerization units have to be taken out of service to replace catalysts, normal turnaround maintenance etc.," he said. "This explanation, or distribution system malfunctions plus the ongoing slump in gasoline demand on a global basis are more likely explanations."
Another explanation posed by market sources has been the collapse of diluent demand in Canada, as a result of the fallout from coronavirus disease 2019 (COVID-19).
IHS Markit's U.S. NGL Markets Weekly report stated that Enterprise's TEPPCO pipeline and terminal, which supplies natural gasoline to Canadian markets, may be getting backed up as a result. IHS Markit is the parent company of OPIS.
Additionally, the report cited the shutdown of a BASF cracker on June 12 as potential source of price pressure, as the cracker can run natural gasoline as a feedstock.
However, if a dearth of demand from all the previously mentioned sources is the culprit, then it hasn't manifested in daily trading volume.
Non-TET natural gasoline had its strongest month of the year in June with about 6.3 million bbl exchanging hands publicly, according to OPIS data. In fact, that's the highest total of the year for any of the benchmark NGLs. Purity ethane had the second highest total at 4.6 million bbl last month.
TimeSeries is OPIS’ historical price database allowing on-demand access for users to pull historical price reports. It houses spot and wholesale rack prices for several energy commodities. Gasoline, diesel, NGLs, resid, feedstocks and futures history is available.
--Reporting by Bobbie Clark, bclark@opisnet.com; and Mary Welge, mwelge@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Natural gas price increases alongside tighter ethane supplies and growing demand, with new export facilities coming onstream, will push US ethane prices higher going into 2021 as the market adapts to new fundamentals, according to IHS Markit analysis.
"The view is changing drastically, not just ethane, for overall fundamentals," said IHS Markit executive director Veeral Mehta in a presentation at the IHS Markit Asia NGLs and Naphtha conference last week. "There is going to be tightness in the markets, more ethane will need to be recovered to meet demand."
IHS Markit has revised its US NGL supply outlook down by 1 million b/d to around 5.2 million b/d in 2023 as the ensuing oil price crash from the coronavirus disease 2019 (COVID-19) pandemic slows down US upstream crude and associated gas production, of which 70% of NGL supply is sourced.
Ethane prices will be driven higher by increasing outright natural gas prices due to the loss of associated gas production and the need to drill for gas from drier fields. Demand will be flattish in 2020 before recovering through to 2025 on growing US petrochemical consumption and boosted by new export capacity to start up at the end of the year.
US ethane prices will trend higher to attract marginal barrels of ethane from farther regions such as the Mid-Continent and the Rockies to the processing and demand hubs in the Gulf Coast. Ethane prices at the Mont Belvieu storage hub will need to rise to cover the equivalent gas price at source, as well as transportation and fractionation costs.
Rejection levels, where ethane is left in the gas stream, will drop fast, Mehta said, with overall US ethane rejection levels expected to tumble to below 400,000 b/d by 2024-25 from a peak of 900,000 b/d last year.
As crude oil prices recover, the favourability of ethane over LPG and naphtha as a petrochemical feedstock to produce ethylene will exist for US Gulf Coast crackers even with the increases in ethane prices, said Mehta. Still, there will be some periods, especially during the summer months, when LPG prices become more favourable.
Energy Transfer's Orbit ethane export facility in the US Gulf Coast, the group's joint venture with China's Satellite Petrochemicals, will be in service in the fourth quarter. The export terminal will have the capacity to export 180,000 b/d alongside 800,000 bbl of refrigerated ethane storage, the group said at the conference.
Energy Transfer's export terminals were a "balancing solution" for Asia NGL demand, said vice-president Ken Squire, with Asian ethane demand currently at 2 million metric tons, and forecast to ramp up to 3.5 million mt in 2021 and 5 million mt in 2023 as new projects come online.
However, there could be considerable upside to future demand in China should there be a change in the political climate.
"Under current US-China relations, nobody's going to sign any long-term contracts," Squire said. "If the political situation would change to be more favourable, then what we would expect to see is that this demand would double with some projects that are sitting in the wings waiting to go," he added.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Karen Tang, ktang@opisnet.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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CPC Corp. is seeking gasoline in a surprise move following the closure of a 50,000 b/d residue fluid catalytic cracker (RFCC) at its Taoyuan refinery in Taiwan for turnaround amid growing demand as governments relax lockdown measures to curb the coronavirus disease 2019 (COVID-19).
The state-run refiner on Tuesday floated the tender to buy 300,000 bbls of 95 RON with maximum sulfur content of 10 ppm for delivery in a five-day range during July 15-31 to various ports including Kaohsiung, Taichung, Taipei and/or Keelung, according to an invitation.
The tender, which closes on July 1 and is valid until July 3, is priced off Singapore 95 RON.
CPC Corp. usually sells gasoline and has not bought any on an open tender basis in the last five years, according to OPIS records, but it may have bought via private negotiations, trading sources said.
The tender came as CPC Corp. shut the RFCC at its 200,000 b/d Taoyuan refinery on May 7 for maintenance works that are expected to last until around Aug. 20, as reported earlier.
Taiwanese gasoline demand is relatively resilient compared to other countries in Asia with local consumption in April down just 1.4% on-year to 4.263 million bbls, according to data from Bureau of Energy, Ministry of Economic Affairs.
In contrast, Japanese consumption in April tumbled 22.7% from a year earlier, while in South Korea it was down 6.8%, according to data from governments.
Consumption across Asia is recovering as lockdown measures were relaxed or lifted.
Some countries such as Japan may increase gasoline imports as their refiners had cut runs due to poor margins after governments took preventive measures over the COVID-19, a Singapore-based trader said.
"We may see some demand from countries where refinery runs were slashed. They have not raised runs fast enough yet to meet demand recovery," the trader said.
In May, Japanese purchases more than doubled to 261,673 kl, or 193,638 mt, Ministry of Economy Trade and Industry (METI) data showed.
Crude runs against the country's nameplate 3.52 million b/d fell to 51.8% in the week to May 30, the lowest on OPIS records of the Petroleum Association of Japan (PAJ) data going back to January 2014.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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China raised retail gasoline and diesel prices for the first time this year as crude oil rebounded to stay above the $40/bbl floor amid fresh concerns over the local demand recovery as pockets of coronavirus disease 2019 (COVID-19) outbreaks raised fears of a second wave.
Domestic gasoline and diesel prices will increase by 120 yuan/mt ($17/mt) and 110 yuan/mt ($15.50/mt), respectively, from the midnight June 28, the National Development and Reform Commission (NDRC) said in a statement on Sunday.
Under its domestic pricing mechanism, refined oil products are adjusted when international crude oil price changes translate to a change of no less 50 yuan/mt ($7.10/mt) for gasoline and diesel within a period of 10 working days.
But China will not adjust retail levels when crude is below $40/bbl or above $130/bbl.
Crude prices recovered with front-month ICE Brent holding above $40/bbl since June 16 as the OPEC+ group extended their supply cut agreement into July and countries eased lockdown measures in an effort to kick-start their economies.
The hike came as domestic gasoline and diesel demand was expected to weaken again amid a fresh COVID-19 outbreak in Beijing.
Authorities in the capital city are trying to curb a new wave of infections, which emerged from a wholesale market in mid-June and anyone wishing to go outside the city must test negative in the last seven days, according to a Beijing-based analyst.
Demand is likely to be hurt more by the pandemic rather than the price increases since the adjustment is minor, analysts said.
"The recent second wave in Beijing is definitely having an impact," said a Singapore-based analyst. "Beijing itself is going back to half-ghost town now, and other cities and provinces are imposing travel restrictions related to Beijing."
It was unclear if weaker local consumption will lead higher exports, analysts said. But refiners are already moving more gasoline to other countries, shipping fixtures showed, just as overseas demand picks up on the back of easing COVID-19 restrictions.
Traders are set to move more gasoline from China to other countries in June than May, according to shipping fixtures.
They have booked nine vessels to load a total of 315,000 mt of gasoline and diesel in June, much more than the six tankers chartered to load 205,000 mt in May, the fixtures showed.
In May, China's gasoline exports tumbled 64.2% from the previous month to 680,000 mt, the lowest since February 2019, according to its General Administration of Customs. Gasoil exports plunged 43.6% to 1.45 million mt.
Local refiners focused on domestic demand as authorities kept local retail prices unchanged after crude prices fell below the $40/bbl floor, which bolstered refining margins considerably.
Analysts doubt if the latest price hike could help increase margins further.
With China's domestic oil demand not expected to recover to pre-outbreak levels until the third quarter and with state-owned refineries expected to lose a large chunk of their export demand compared with last year, independents will face more intense domestic competition, IHS Markit said a report on the sector issued on May 29.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Asian buyers are paying more for naphtha with high paraffin content while heavy full range naphtha (HFRN) flipped into discount from premium a month ago as olefins margins outshine aromatics, market participants said.
Supply of all naphtha grades tightened because of lower global refinery runs due to fuel demand loss stemming from coronavirus disease 2019 (COVID-19) mobility restrictions. At the same time, resilient petrochemical demand has kept Asia cracker run rates at more than 85% in recent months, widening the supply shortfall, they said.
"Overall light naphtha production is not high because of refinery run cuts.
Lower arbitrage is contributing to the prevailing tightness," a trade source said.
Availability from the Middle East, the biggest supplier of light naphtha, has tightened after refiners cut output, several sources said, without quantifying the extent of the reduction.
The paraffin content of Middle East full range naphtha varies depending on the refiner, said a trade source. Qatar Petroleum typically produces naphtha with 69-70% paraffin while other producers vary from 75-83%, the source added.
In addition to reduced volumes, Middle Eastern barrels have also become heavier, some sources said. Weak gasoline and aromatics margins may have prompted refiners to blend heavier grades and possibly jet fuel into naphtha, a trade source said.
Middle East full range naphtha fetched a premium, with Idemitsu Kosan paying as much as plus $22/mt for H1 August with 15-day pricing, said a source. The buyer paid $16-$22/mt, including an 85% paraffin cargo, to Tokuyama and Chiba in recent days, sources said.
"It has been a mix of supply and demand shocks. Japan is a lover of paraffins and has a strong preference for Middle Eastern cargoes, and now the Middle East is cutting volumes," another trade source said.
Arbitrage inflow from the West, another supply source, particularly of HFRN, is also expected to fall, with only about 900,000 mt booked to date for August arrival, two sources said.
There will be further July-loading fixtures although the total volume for August arrival is expected to be below average, one of the sources added. The average inflow is 1.7-1.8 million mt, a source previously said.
European naphtha has strengthened on the back of decreased imports, particularly from Russia, and strong demand from crackers as well as gasoline blending, as reported by OPIS.
"Asia was awash with arbitrage barrels in May and June because there was no gasoline blending demand. Now gasoline demand has returned, cracker demand is still there, but refinery runs are recovering at a slow pace because middle distillate margins remain weak," said a northeast Asian buyer.
HFRN, favored for aromatic production, is trading at a discount of $1-$2/mt to open specification naphtha (OSN) with minimum paraffin of 65%, in a reversal of H1 July, when it fetched $1-$2/mt premiums, OPIS data show.
For H1 August delivery, Hanwha Total Petrochemical (HTC) and GS Caltex bought HFRN at premiums of $11-$13/mt while Korea Petrochemical Industry Co. Ltd. (KPIC) paid $13-14/mt for light naphtha with minimum 70% paraffin, as reported.
For Aug. 11-20, Formosa Petrochemical Corp. paid around plus $15/mt for minimum 70% paraffin naphtha.
A month ago, HTC and GS Caltex bought H1 July HFRN at around plus $3/mt, compared with the plus $1-$2/mt paid by KPIC and LG Chem for lighter grades, the data show.
Even though the tightness in naphtha supply is being felt across the board, comparatively strong olefins margins versus aromatics may explain the shift in the light versus heavy price relationship, some sources said.
"Lighter grade is more valuable and in good demand recently," said a third trade source.
Ethylene operating rates in June were estimated at 86% for Northeast Asia and 87% for Southeast Asia, according to the latest IHS Markit Asia Light Olefins Weekly Market Report, little changed from 86% for both regions in May.
"LPG has been expensive but prices are coming down and that may help to ease the tight naphtha balance soon," the northeast Asian buyer added.
Japanese and Korean cracker operators usually switch from naphtha to propane and butane when the propane or LPG to naphtha ratio falls below 90%, said sources.
The propane-to-naphtha ratio was at 86% on Thursday, falling from a six-year high of 179% on April 15, according to OPIS data.
LPG's competitiveness as a cracker feedstock has increased although the gas can only replace up to 20% of naphtha, according to the latest Asian Petrochemical Feedstock Market Outlook weekly report.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com, Masayuki Kitano Masayuki.Kitano@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Intermittent power outages in Karachi has forced Pakistan to import high sulfur fuel oil (HSFO) for the first time in more than a year amid insufficient liquefied natural gas (LNG) and a rebound in economic activity as coronavirus disease 2019 (COVID-19) restrictions are loosened, a Karachi-based trader and market sources said.
State-owned Pakistan State Oil (PSO) issued a tender to buy HSFO for delivery to Port Qasim on July 9-18, which closes on June 29, according to a tender advertisement on the Public Procurement Regulatory Authority (Pakistan) portal.
It sought two parcels of 70,000 mt each of 180 CST HSFO with a maximum sulfur content of 3.5% for K-Electric amid a shortage of furnace oil, market sources said.
PSO last sought a similar cargo also to Port Qasim on June 11-30, 2019, but the outcome could not be confirmed.
On June 20, Pakistan authorities approved measures by its petroleum division to ensure adequate supplies of HSFO to meet power requirements, as reported by the national Associated Press of Pakistan news agency.
"We are using LNG but during these peak months this would be one of the imports as lockdowns from COVID-19 ease," added the Karachi-based trader.
PSO imported 79,800 b/d of residual fuel oil in 2018 and 20,000 b/d in 2019, according to IHS Markit data. Over the past three years, Islamabad has been trying to replace fuel oil with the cleaner-burning LNG, partly through bans on fuel oil imports that were implemented intermittently.
But the South Asia country cut LNG deliveries in April during the COVID-19 lockdown and local refineries weren't producing enough HSFO to meet domestic demand when the lockdowns ease, said the sources. Some of its power plants in the north run on LNG.
HSFO is also in demand in the textile industry for running steam boilers in the dyeing, drying and heating processes, which has also resumed manufacturing as the government looked to kick-start its economy.
K-Electric is a private firm that owns 2.8 GW of power generation capacity, supplying electricity to the Karachi metropolitan area.
The firm switched to using regasified LNG instead over the past month or so due to shortages in the domestic HSFO supply, a Pakistani LNG trader said.
Pakistan imported 3.14 million mt of LNG from January to May this year, 16% less on-year due to demand destruction from COVID-19, shipping data from IHS Markit showed. It bought 8.5 million mt in 2019, 24.3% more than a year ago, raising hopes that the country could triple its import of the super chilled gas within the next five years.
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--Reporting by Thomas Cho, Thomas.Cho@ihsmarkit.com, additional reporting by Carrie Ho, Carrie.Ho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Global commodities trader Gunvor is mothballing its 107,500-b/d Antwerp refinery in Belgium following the cratering of European refining margins during the coronavirus disease 2019 (COVID-19) pandemic, the company's CEO Torbjorn Tornqvist has announced.
"The coronavirus pandemic has turned an already challenging situation into one that's unsupportable," said Tornqvist. "Gunvor Petroleum Antwerp has had and will now certainly continue to experience negative cash flow on a magnitude that is not affordable for the group," he added.
The refinery stopped operating on May 26 to conduct maintenance, Gunvor said in a previous statement.
European refining margins have slumped as a result of the hit to demand caused by the COVID-19 pandemic, with cracks -- approximate measures of refining profitability -- falling into double-digit negative territory for gasoline.
Refining diesel has remained profitable throughout the pandemic, but even the OPIS-assessed northwest European diesel crack slumped from $13.58/bbl on March 11 to just $0.28/bbl on May 7.
European refining margins for most products have improved but remain low by seasonal standards, with the OPIS-assessed northwest European diesel and Eurobob gasoline cracks pegged at $5.60/bbl and $3.15/bbl, respectively, on Monday.
Gunvor's Antwerp refinery has a much lower potential output than several other refineries in Europe's key Amsterdam-Rotterdam-Antwerp refining hub, and its size is one of several factors adversely affecting its strength, IHS Markit refining and marketing consulting director Hedi Grati told OPIS.
"Gunvor's refinery in Antwerp is smaller and less complex than its peers in the port and across the border in nearby Rotterdam. Additionally, there is less integration with marketing activities such as fuels retail, which would otherwise provide some more security of demand," said Grati.
"The continued strength of Urals crude, at a premium to dated Brent, must have seriously weighed on the refinery's bottom line," Grati added. The refinery was designed to process medium-sulfur crude oil, such as the Urals grade.
The European refining sector is expected by most analysts to see rationalization over the coming decade, with IHS Markit consequently forecasting crude runs in Europe falling 1.8 million b/d from 2019 levels to 10.8 million b/d by 2025.
IHS Markit is the parent company of OPIS.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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The restart of the 300,000 b/d Petronas-Saudi Aramco joint venture Pengerang Refining and Petrochemical (PRefChem) facility after an explosion was pushed back due to manpower issues leading to the sale of several million barrels of crude oil that were in floating storage, trading sources said.
The refinery, in the southern Malaysian Johor state, was shut after a massive fire and explosion on March 15 that killed five people. The incident, the second in a year, occurred at a Diesel Hydro Treating Unit (DHT), the company said in a March 16 statement.
The facility was originally due to resume operations in August, however, lockdown measures taken by Malaysia to curb the spread of the coronavirus disease 2019 (COVID-19) led to manpower shortages similar to that faced by refiners elsewhere in Asia during this period, the sources said.
In many cases refiners were forced to delay maintenance until workers could safely get to the site but in other cases that require specialist foreign staff, the works were pushed back to later in the year once international air travel were lifted or exemptions given. Malaysia eased local restrictions earlier in June after three months but its borders remain closed.
"I don't want to say it's been suspended indefinitely but that's why they were confident in selling these crude oil cargoes," said one trading source, adding that Aramco Trading Co. sold three very large crude carrier (VLCC) loads of Murban and one of Agbami.
Murban and Agbami are light sweet crudes which Pengerang was processing as it coped with the shutdown of desulfurizer units in two separate incidents.
The refinery was saddled with issues since it began production last year. In April 2019, another massive fire and explosion almost completely destroyed an atmospheric residue desulphurizer (ARDS), crippling operations as the site was no longer able to process intended sour crudes.
Trading sources said it made sense that the cargoes were sold in the spot market once it became clear that an imminent resumption of operations were not in the offing as current prices made the trades worthwhile amid a losing proposition of keeping them in storage in the absence of a profitable contango.
The Murban was probably bought at a discount of around $4/bbl to Dubai if they were loaded in early April and sold this week at premiums of as much as $1/bbl, which is a good deal, said one trading source, noting that onshore crude oil tanks in Pengerang were also filled to the brim.
Crude oil strengthened considerably in the past few weeks after incurring sharp falls in April when supplies were in abundance leading to a super contango. A combination of a rebound in demand from the COVID-19 destruction and an OPEC+ pact to cut output led to the price recovery, pushing up differentials and quashing the contango.
PRefChem officials did not immediately reply to emails seeking comment.
Investigation into the Pengerang explosion would probably take a month, an official at Malaysia's Department of Occupational Safety and Health (DOSH) said at that time, adding that it could take longer if it turns out to be a complicated case.
The ARDS, one of two 70,000 b/d units at the site, that was destroyed in the 2019 explosion provides low-sulfur residue feedstock to a 140,000 b/d residue fluid catalytic cracker (RFCC). The other ARDS was shut due to emission issues, according to local media at that time.
Consequently, the refinery as a whole, and the RFCC in particular, was running at very low rates, market sources said. The fire-hit ARDS was due to restart in the middle of this year, Petronas said in a quarterly report.
The refinery is designed to produce 98,000 b/d of gasoline, 28,000 b/d of jet fuel, 88,000 b/d of diesel, 5,000 b/d of fuel oil and 458,000 mt/year of slurry sulfur. Its gasoline and diesel meet Euro 5 specifications.
The refinery also provides feedstock to an integrated petrochemical complex with a nameplate capacity of 3.3 million mt/year. The cracker has a capacity to produce 1.26 million mt/year of ethylene, 600,000 mt/year of propylene and 180,000 mt/year of butadiene, according to IHS Markit data.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Five Very Large Gas Carriers (VLGCs) are heading towards northwest Europe from the U.S., arresting the slump in LPG imports in the second quarter, according to IHS Markit Waterborne data.
The total LPG import tally for July delivery has subsequently leapt to 190,000 metric tons from a previous estimate of 46,000 mt, the data show.
The sudden import spurt appears to have been triggered by a deepening in the spread between CIF Amsterdam, Rotterdam, Antwerp (ARA) propane and CIF northwest Europe (NWE) naphtha, amid demand for a greater intake of propane as feedstock.
Propane's discount to CIF NWE naphtha deepened for July, ending at minus $46/t mid-week, from minus $8/t at the start of June, according to the data in the OPIS Europe LPG & Naphtha Report. Early-June bidding for CIF ARA propane by a petrochemical major in NW Europe had continually pitched buyside levels between $10 and $15/mt deeper when compared to propane/naphtha spreads at the time.
The first early-July cargo is expected on the Gas Aquarius, along with the Hellas Gladiator, Vega Star, Ronald N and Copernicus. The first three cargoes will have U.S. Gulf Coast-origin LPG, while the latter two loaded at Marcus Hook, on the U.S. East Coast. All five VGLCs are expected to arrive during the first half of July, according to tracking data.
European imports have slumped in Q2 due to a cave-in for demand following lockdowns in Europe to slow the spread of the coronavirus disease 2019 (COVID-19) pandemic. Propane imports were 345,000 mt in March, and fell to 180,000 mt in April, 80,000 mt in May and 114,000 tons in June to date.
Northwest European imports over the same three-month period last year were pegged at 235,000 mt, 372,000 mt and 327,000 mt, respectively, according to OPIS data.
Weak arbitrage economics had hindered an earlier return to more typical U.S. to NW Europe LPG flows earlier last month, according to sources, as netback values plummeted.
Netbacks to the U.S. from northwest Europe for the second half of June for barrels lifting from the U.S. Gulf Coast between 11-15 May turned negative, hitting a nadir of minus 1.75cts/gal. For the wider 5-20 May period, netbacks failed to break above plus 1cts/gal, according to OPIS data, rendering U.S. propane exports to northwest Europe temporarily uneconomic.
Still, the narrow arbitrage window has given rise to some flexibility on grades to enable some of the propane cargoes to come to Europe. Two of the ships, the Gas Aquarius and Ronald N, are expected to drop part-cargoes of butane into Morocco, North Africa, a more economical trade, and then head for northwest Europe to discharge propane.
"With East [Asia] looking weak for the interim, [it] makes sense to try and leverage it any way you can," said one source describing the part-cargo discharges amid scarce U.S.-northwest Europe propane arbitrage opportunities.
Gain greater perspective on global spot prices for naphtha, propane and butane.
OPIS developed the pricing in our Europe LPG & Naphtha Report to reflect the market’s desire for an unbiased methodology and accurate spot price benchmark in northwest Europe and the Mediterranean.
--Reporting by Charles Kim; ckim@opisnet.com; Dermot McGowan, dmcgowan@opisnet.com;
--Editing by Rob Sheridan, rsheridan@opisnet.com
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California refined products margins are better than they were when Marathon temporarily idled its 161,000-b/d Martinez refinery in April, but fuel demand has not improved to where a restart of the complex is likely in 2020, sources said.
Some large unbranded wholesale customers told OPIS that they have been privately informed by Martinez sales executives that a restart in 2020 appears out of the question. But the Bay Area refinery is not a candidate for permanent closure, given its complexity and the eventual return of demand for transportation fuel in a post-coronavirus disease 2019 (COVID-19) environment.
June has seen Marathon actively purchasing Bay Area gasoline from other processors. Those purchases should enable the company to accommodate the needs of the nearly 3,000 California service stations that offer ARCO, Shell, Speedway and USA Gas in the Golden State. The average Golden State rack-to-retail margin year to date in 2020 has been 65cts/gal, leaving plenty of room to buy incremental gas and still make a tidy profit on the street.
A Marathon spokesperson declined to comment on Martinez refinery operations in the rest of 2020, emphasizing that top brass was constantly evaluating conditions with an intent to restart when "demand warrants."
Pacific Coast traders said there's not much chance of a consumption rebound in this year's driving season, and western margins traditionally slump in the last 100 days in any calendar year. The idling of Martinez in late April tilted gasoline supply toward a more balanced market, but prospects for diesel and jet fuel in the region have soured.
Some traders have said a restart would send spot prices sharply lower for CARBOB, CARB diesel and jet fuel. San Francisco CARBOB fetched an average price of around $1.30/gal in the spot market last week, representing modest basis premiums of 7.5-16.5cts/gal to the NYMEX RBOB contract. S.F. CARB diesel spot prices averaged about $1.17/gal, or a nominal 3.5-4.25cts/gal over the ULSD futures contract.
In comparison, the five-year average of mid-June weekly prices for S.F. CARBOB and S.F. CARB diesel between 2015 and 2019 was $1.85/gal and $1.82/gal, respectively, according to OPIS historical spot pricing data. Even so, Northern California current market values are about 62cts/gal stronger than when the Martinez refinery was idled on April 27.
California was one of the first states to get hit by the COVID-19 pandemic and S.F. CARBOB brushed an outright price bottom of 30cts/gal in early spring, recovering to a weekly average of 58cts/gal ahead of the Martinez shutdown. The decision to idle Martinez may also have been influenced by the loss of some Ecuadorian crude earlier this year. The plant runs heavy California crude as well as barrels from Ecuador, Colombia and Saudi Arabia.
More recently, S.F. CARBOB spot market trading around 14cts/gal above RBOB futures, or about $1.32/gal Tuesday around 12 p.m. ET, put the Bay Area gasoline "crack" at about $15/bbl over Brent crude, a far cry from the $20-$30/bbl cracks seen during other recent California driving seasons.
Bringing back a 161,000-b/d refinery might tighten up the crude market but could tilt gasoline back into the "sloppy" category that prevailed for the first part of 2020.
The U.S. West Coast PADD5 region represents perhaps the most disciplined refining area of the country. Before the COVID-19-inspired demand destruction, refiners were operating at about 87% of capacity, according to statistics compiled by the U.S. Energy Information Administration (EIA). Regional run cuts and the idling of Martinez pulled refinery utilization rates to just above 61% of capacity for the week ending June 5, according to EIA. A cursory glance at other regions finds the East Coast with a lower rate of 51.3%, but that's only because the closed-for-good Philadelphia Energy Solutions refinery's 336,000-b/d is still counted in the base capacity. PADDs 2, 3 and 4 have seen refinery runs rebound to over 75% utilization.
Recent gasoline demand destruction in California has been around 20%-25%, showing recovery for the state in the West region (including the Rockies) where retail demand was down 52% on the year for the week ending April 11, according to OPIS DemandPro. California Gov. Gavin Newsom (D) issued a stay-at-home order in mid-March to slow the COVID-19 spread and began a phased lifting of restrictions in May. California's COVID-19 cases climbed by over 3,061 in the last week.
The Martinez refinery could be restarted in relatively short order if demand warranted, with the plant capable of returning to normal operations within two weeks, a spokesperson told OPIS.
Longer term, the refinery is viewed as a keeper, although Marathon might have to make substantial investments in the state in renewable diesel. Refinery experts who have analyzed all of California's refineries list Valero's Wilmington plant as the most likely candidate for eventual closure, and they are also keeping an eye on Phillips 66's coupled plants in Rodeo and Santa Maria.
Many of the large Bay Area refineries have high complexity, which isn't necessarily paying off these days since heavy sour crude blends are not fetching large discounts to light sweet barrels. Break-even numbers for the complex refineries in the Bay tend to be much higher than typical refineries in other regions.
Marathon's Martinez plant isn't the only refinery likely to remain on the shelf for months. The refiner also idled its 26,000-b/d refinery in Gallup, N.M., and a restart there does not appear imminent.
Meanwhile, sources believe that the ex-HOVENSA plant in St. Croix in the U.S. Virgin Islands that was originally expected to run up to 200,000 b/d of crude in early 2020 in January will not be manufacturing gasoline or diesel this summer. There is no word on when the 135,000-b/d Come-by-Chance refinery in Newfoundland will be resurrected by new owner Irving, and a deal to refurbish and restart a 335,000-b/d Curacao refinery by Klesch Group has been delayed by COVID-19. Demand concerns are also the probable rationale behind the delayed target date for the expansion of ExxonMobil's Beaumont, Texas, refinery from 350,000 b/d to 600,000 b/d.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Tom Kloza, tkoza@opisnet.com, Lisa Street, lstreet@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Kuwait Petroleum Corp. (KPC) concluded its August 2020-July 2021 term naphtha sales at lower premiums with cuts of as much as 31.8% versus the April 2020-March 2021 contract on expectations of increased supply, market sources said.
KPC settled its full range naphtha (FRN) at a premium of $15/mt to Middle East prices and its light paraffinic naphtha at plus $16.50/mt on an FOB basis, they said.
Prices for both grades were reduced by $7/mt, with FRN down 31.8% from its plus $22/mt for the April 2020-March 2021 period while light paraffinic naphtha fell by 29.8% from plus $23.50, the sources said.
The lower premiums likely reflect shifting supply and demand fundamentals as refiners ramp up runs to meet post-coronavirus disease 2019 (COVID-19) fuel demand recovery, said April Tan, IHS Markit downstream associate director in Singapore.
To counter the already high distillate and diesel inventories, "... refiners are likely to adjust production outputs more towards naphtha ... and this will add pressure to the supply balance and lower premiums," Tan said.
Compared to a year ago, the latest prices are $0.50/mt higher.
For August 2019-July 2020, FRN was done at premium of $14.50/mt and light paraffinic at plus $16/mt, the sources said.
KPC is the fourth largest Middle East supplier of naphtha to Asia, after Abu Dhabi National Oil Co. (Adnoc), Qatar Petroleum and Saudi Aramco, according to the sources.
Adnoc last month cut its H2 2020 naphtha term premium by as much as $8/mt, or 32%, for its splitter naphtha, from H1 2020. It also reduced its H2 2020 paraffinic naphtha premium by $7/mt, or 26%, to plus $20/mt.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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The 404,000 b/d Pernis refinery near Rotterdam in the Netherlands, Europe's largest refinery, is scheduled to come back from its largest turnaround in several years by the end of this month, market sources said today.
Refinery operator Royal Dutch Shell has started offering diesel to load from Pernis before the end of the month, according to two European diesel market sources. Shell is also offering marine gasoil, known as DMA, for loading at Pernis in July, said a marine fuel market source.
The entire refinery with two 200,000-b/d CDUs went offline for a turnaround in the middle of April, and sources in the area said maintenance would last throughout May and June. The refinery is set come back online at a moment when European refining margins remain low but have started to creep up.
Northwest European diesel and jet FOB barge cracks were assessed at $4.35/bbl and $0.84/bbl on Friday. The diesel crack, an approximate measure of refining profitability, hit a low of $0.27/bbl on May 7 and jet cracks reached a bottom of minus $8.88/bbl on May 5, as oil product demand was crushed by authorities restricting travel at the onset of the coronavirus disease 2019 (COVID-19) pandemic.
Shell declined to provide a date on when Pernis will come back from turnaround.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Three of the largest airlines in Europe, British Airways (BA), easyJet and Ryanair, are suing the UK government over a 14-day quarantine ruling, BA parent company the IAG Group said Friday.
The UK Government decreed that all passengers arriving to the United Kingdom from overseas, with the exception of Ireland, will have to quarantine for 14 days from 8 June onwards to stem the potential spread of the coronavirus disease 2019 (COVID-19). The three airlines argue that the rule is ineffective and will have a devastating effect on the British aviation industry.
"British Airways, easyJet and Ryanair have launched their legal action against the UK government's flawed quarantine which will have a devastating effect on British tourism and the wider economy and destroy thousands of jobs. The airlines have asked for their judicial review to be heard as soon as possible," the IAG Group said in a statement.
The three airlines also argue that this quarantine policy should only be imposed on passengers travelling to the UK from high-risk countries.
"Continued restrictions on air travel are having a significant financial effect on the industry including airlines, tour operators, airports and their supply chains, which may lead to further financial failures the longer these restrictions remain in place," Louise Congdon, managing partner of aviation consultancy York Aviation told OPIS Friday.
Lifting quarantine measures could have a positive impact on European jet fuel demand, according to industry sources, as the quarantine requirement is one of the deterrents to UK citizens booking holidays abroad.
One market insider said that UK lifting travel restrictions could see jet fuel demand in the Mediterranean region increase, suggesting that spikes in jet fuel prices this summer could be likely.
"Flying schedules for June are already quite high, Italy and Greece are begging for tourists to come," he said. "If the UK releases its borders then we could see a spike in the Mediterranean."
"Looser restrictions would help jet demand's recovery," said IHS Markit associate director Eleanor Budds. Demand for jet fuel is also sensitive to other factors, such as the fear of catching the virus and travel restrictions in other countries, Budds said.
Get daily expert analysis of the Northwest Europe and Mediterranean jet fuel, ULSD and gasoil markets with OPIS Europe Jet, Diesel & Gasoil Report Try it free for 21 days
--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Northwest Europe naphtha values strengthened against the refinery complex in April and May, with support coming from higher arbitrage flows to Asia alongside burgeoning petrochemical feedstock demand, while other refined products in Europe saw demand crumple due to the confinement measures brought about by the coronavirus 2019 disease (COVID-19).
NWE naphtha front month cracks to Dated Brent firmed to an average of minus $10.18/bbl in April and minus $5.95/bbl in May, according OPIS data, while average monthly OPIS CIF NWE naphtha prices jumped 39% from April to $226.53/t in May. Average monthly Brent futures at the 4:30 p.m. BST marker price gained 17.7% to $31.95/bbl over the same period.
Supply
A heavy outflow of European naphtha to Asia has dominated the market in recent months, with some 3.2 million-3.4 million tons delivered in April and a multiyear high of 3.4 million tons arriving in May, according to OPIS Asia.
Typical monthly arbitrage volumes are placed at around 1.7 million-1.8 million tons.
The East/West (E/W) naphtha spread ballooned on the back of these to a multiyear high of $87.25/t on April 22 as Asian markets eased out of lockdown measures.
Availabilities for Long Range 1 (60,000 tons) and Long Range 2 (80,000 tons) vessels tightened in a scramble for freight or floating storage usage.
Long Range 2 (LR2) freight rates for the Mediterranean to Japan route surged to around $4 million lumpsum compared to a more typical $1 million-$1.5 million lumpsum, according to shipping reports seen by OPIS, and subsequently, many of the arbitrage cargoes were later fixed on Medium Range (40,000 tons) vessels.
By the beginning of May, one source signaled they were "not sure about how strong Asian appetite is" while supply to Asia was boosted by the return of Middle Eastern refineries from turnaround midmonth, leading the E/W spread to crash to a low of plus $17.25/ton by May 20.
Naphtha market length in northwest Europe was prevalent and one market source noted that at one point in May, over 10 parcels were looking for homes with one cargo reportedly sitting outside Amsterdam-Rotterdam-Antwerp (ARA) since early April.
"Too much product around, no blending demand and tanks full of more valuable products," a trader commented.
"It has gotten a bit better, especially in the Med, but still plenty of naphtha around in the north," another trader said in mid-May.
The deep contango structure for April and May emphasized naphtha's prompt oversupply, the front months spread averaging minus $16.82/t in April and -$9.26/t in May.
Supply reductions became apparent in May, as lower refinery runs curtailed the flow of naphtha to the market.
According to shipping reports compiled by OPIS, naphtha loadings in the region covering northern and northwest Europe, the Baltic, Mediterranean, Black Sea and Algeria dropped 0.23 million tons to 3.12 million tons from April to May.
In addition, condensates loadings were sharply cut by 83,000 tons to 97,000 tons, and shipping volumes of reformate were reduced by 58,000 tons to 335,000 tons.
Demand
Naphtha did not experience the same demand crushing effect COVID-19 lockdown measures had on transport fuels in April and first-half May as support came from the petrochemical sector amid discounted prices to rival gas liquids feedstocks.
Compared to CIF NWE naphtha, CIF ARA propane moved from an average discount of $142.10/t in February to a premium of $86/t in April, while notional OPIS CIF NWE ethane values soared to unforeseen premiums of plus $143.66/t ex-Marcus Hook and plus $150.22/t ex-Morgan's Point in April, in stark contrast to discounts of $175.38/t and $166.96/t in February.
European steam cracker operators enjoyed healthy margins in April as the European ethylene contract price was set relatively high at 720 euros/t ($788/t).
Moreover, for cracker co-products, sources noted that benzene margins were close to break even.
"Petchems ticking over nicely, but we aren't seeing much blend demand," a source had said.
Sources added naphtha, with higher yields of co-products such as aromatics, was preferred to lighter feeds with benzene margins near break even in April.
Going into May, naphtha's economical advantage receded as naphtha prices recovered in hand with the ethylene contract price slumping to 620 euros/t ($674.31/t).
The propane/naphtha spread shriveled to plus $23/t in May, while the notional ethane/naphtha declined to plus $49.98/t ex-Marcus Hook and plus $129.25/t Morgan's Point.
Buying interest for naphtha from the gasoline blending sector has yet to take off with the gasoline/naphtha spread hovering at an average of $26.11/t in April and $27.91/t in May, falling short of the $35/t mark seen as a "rule of thumb" used by market players to encourage the use of naphtha as a blend stock, on top of already low gasoline fuel consumption in Europe.
Differentials for open-specification (OSN) naphtha to the flat price ranged from minus $11/t to minus $4.50/t in May compared to a band of minus $18/t to minus $11/t in April, reflecting tighter May availability.
Paraffinic naphtha sank to discounts of minus $18/t to parity with the flat price in April before partially recovering to the minus $7.50/t to plus $2/t band in May, with more buying interest from the petrochemical sector compared to OSN due to its higher paraffin content.
Gain greater perspective on global spot prices for naphtha, propane and butane.
OPIS developed the pricing in our Europe LPG & Naphtha Report to reflect the market’s desire for an unbiased methodology and accurate spot price benchmark in northwest Europe and the Mediterranean.
---OPIS Europe LPG and Naphtha, OPIS-Energy-LPEdsEurope@ihsmarkit.com;
--Editing by Karen Tang; ktang@opisnet.com
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Demand recovery and refinery run rates are the two uncertainties trading sources consistently raise when discussing Asian crude oil imports in the coming months and its impact on prices now that the OPEC+ group have got a handle on supply.
Going forward, rebalancing of the oil market will not only depend on the speed of global demand recovery but also whether the incremental demand is met by tapping on storage barrels of both crude and products, they said.
Middle East official selling prices (OSPs) for July crude to Asian buyers were raised sharply this week as Abu Dhabi National Oil Co. (Adnoc) lifted prices, following on the heels of Saudi Aramco with fellow producers in Iraq, Kuwait and Qatar expected to do the same. This is likely to attract distressed cargoes from across the world, market sources said.
However, whether the OSP increase and possible reluctance among term buyers to take full contractual volumes would draw out crude oil currently in storage as part of the contango trading strategy or even flush out clean products on board vessels in place of higher refinery runs is still a big unknown, they said.
“Crude oil supply is tight, the producers have achieved what they wanted. Now the recovery depends on demand. How big of a dent will the cuts make on the storage barrels is the big question,” said one trader, adding that last month participants did not sell a lot of their storage cargoes.
“Refiners paid the higher premiums and bought spot Middle East cargoes,” he said, adding that the Oman-Dubai spread widened on the back of this demand to over $2/bbl before falling to about $1.50/bbl over the past weeks. The spread was in the negative prior to the unilateral Saudi-led June production cut.
In May, on the back of these additional output reductions, premiums for Middle East crude soared and the price curve strengthened considerably in line with the reduced supplies, leading in part to the higher July OSPs. The extra cut was, as expected, not extended to July.
“The voluntary cut has served its purpose and we are moving on. A good chunk of what we will increase in July will go into domestic consumption,” Saudi Energy Minister Prince Abdulaziz bin Salman was quoted as saying in an OPEC+ virtual news conference.
The higher OSP, which was above most term buyers price views, was an indication of a return of global oil demand, Prince Abdulaziz said, however, some refiners are voicing their displeasure.
“The preference for sour barrels is there,” said one trading source, which suggest refiners would at least take contractual minimum in the extreme with most likely to load full volumes since the Middle East barrels are only less economical than a few supply sources such as the U.S. Gulf Coast.
“If anything, refiners have to look at arbitrage barrels for incremental volumes. Freight has weakened a lot so it should help the sour barrels land better,” he added.
Trading sources said Asian refiners will seek out their favorite deep-sea spot sour crude such Johan Sverdrup, Grane, Forties, CPC Blend, Urals as well as U.S. cargoes such as WTI and Thunder Horse. Latest shipping fixtures show more volumes heading to the region from Mexico, which is pulling back from the OPEC+ cuts.
Reducing Storage Barrels Key to Shifting Market Fundamentals
However, for the market to re-balance more barrels have to come from storage, which for now is slow to takeoff with crude in tanks still at high levels, they said.
There are still about 170 million barrels of crude oil stored on board 171 vessels at the start of June, data from IHS Markit’s Commodities at Sea show. At its peak about a month ago in mid-May more that 240 million barrels were kept on tankers compared with the usual around 60 million barrels when there is no super contango, the data show.
For a significant dent to be made, global fuel demand growth has to be further down the road in its recovery path, they said.
Strong, Sustained Demand Recovery Necessary
IHS Markit estimates that at the height of the coronavirus disease 2019 (COVID-19) global oil demand shrank by a massive 18 million b/d in the second quarter with consumption forecast to fall an average 9.5 million b/d this year.
Demand in Asia was expected to contract by about 4.5 million b/d in the first quarter and by 4.9 million b/d in the second quarter, according to an IHS Markit report on the region published on May 19.
“Although we expect the trough to have been over in April on a monthly basis as regional countries start to ease their containment measures, recovery will be gradual amid change in consumption patterns and fears over a second wave of infections,” it said in the report.
It is this patchy and uncertain recovery that traders point as the biggest obstacle to a sustained rebound in crude oil prices.
“If refiners crank up runs by a lot during this recovery then all of the oil products that are in storage won’t be used up and the oversupply situation won’t be resolved,” another trading source said.
Already refiners in the two major consuming centers, China and India, are close to or even reached pre-COVID operating rates, government and company data show.
“If you look at the product inventories, both onshore and on tankers, the outlook should be bearish,” the source added.
China, for example, ramped up crude oil imports in the first half of this year with purchases soaring to a record 11.34 million b/d in May and there are expectations that it could reduce purchases for delivery in the second half, something it did over the course of 2018.
“By how much 2H 2020 imports will pull back depends on refinery runs (which in turn depends on oil demand recovery in domestic and overseas markets) and availability of storage capacity. All these factors are 2020 specific and may not be directly comparable to 2018,” said Feng Xiaonan, IHS Markit analyst in Beijing.
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--Reporting by Carrie Ho, Carrie.Ho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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The oil tanker IDI is shipping a jet fuel cargo to the US from Italy in a rare reverse trade amid a supply glut on falling demand across Europe, as demand slumps following travel restrictions to slow the coronavirus disease 2019 (COVID-19) pandemic.
The IDI was chartered by BP and loaded 37,000 metric tons of jet fuel from the Mediterranean port of Augusta in Italy on June 4, according to a shipbroker report. The tanker is due to arrive in New York around June 27, according to data from IHS Markit's Maritime Intelligence Network.
Europe typically imports in excess of a million tons of jet fuel each month as demand outpaces supply across the region. However, jet fuel demand plummeted as airlines cancelled flights and grounded aircraft in the wake of the COVID-19 pandemic. This is the first jet cargo sailing from Europe to the US since January when Yasa Flamingo hauled a 53,000-mt jet fuel cargo from Amsterdam to Los Angeles.
"We have seen the US buying jet, because US refiners are not producing that much jet at all while aviation demand has slowly come back," one source commented. "It looks like there is a surplus of supply in the Europe at the moment, with not much flying," another source added.
Unipec was also looking to purchase a 37,000-mt jet cargo loading from the Turkish port of Aliaga between June 21 and June 23, with options to discharge in a port across the Atlantic.
FOB New York harbor jet fuel cargo prices were pegged at a $22.37/mt premium to FOB NWE cargo price on Tuesday, OPIS data show. Kerosene stocks in the PADD 1 region, encompassing New York state, were 1.1 million bbl below the 5-year average, according to the latest weekly data from the U.S Energy Information Administration.
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--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Japanese crude throughput increased last week for the first time in six weeks after plummeting to levels not seen in at least six year as refiners raised runs in anticipation of a renewed fuel consumption after a nationwide state of emergency was lifted.
Refiners processed 13.433 million bbls, or 1.92 million b/d, in the week to June 6, up 5.3% on-week, according to the Petroleum Association of Japan (PAJ) data on Wednesday.
Throughput, which fell to 12.757 million bbls in the previous week, the lowest on OPIS records of PAJ data going back to January 2014, has been declining since the week ended April 25.
Crude runs against the country's nameplate 3.52 million b/d rose to 54.5% from 51.8% a week ago, also the lowest on the records.
The utilization rate of crude distillation units (CDUs) advanced to 77.9% because of a continuous reduction in total operable capacity, which lost another 42,857 b/d to 2.46 million b/d.
""Japanese refiners will gradually raise runs to meet recovering consumption after the government lifted the emergency state," said Matthew Chew, principal research analyst at IHS Markit in Singapore.
Throughput is predicted to grow from 2.268 million b/d in May to 2.403 million b/d in June, 2.631 million b/d in July and 2.845 million b/d in August, Chew said.
IHS Markit revised upwards fuel consumption forecast for the second quarter, according to Chew.
Overall demand in the April-June period is currently predicted to fall 480,000 b/d from a year earlier compared with the earlier forecast of a 487,000 b/d drop. In the third quarter, the decline is forecast to slow down to 299,000 b/d. Refiners across Asia are increasing runs as authorities relaxed lockdown measures to contain the coronavirus disease 2019 (COVID-19).
Indian Oil Corp. (IOC) in May raised utilization rates to 75-80% from 39% in April, as reported earlier. Bharat Petroleum Corp. Ltd. (BPCL) said it will resume full operation where possible after raising throughput to 77% of capacity as of May 31 from 63% in April.
Chinese refinery runs in May were estimated to see more month-on-month improvement to 70% from 55 % in February, according to the IHS Markit China Refining and Marketing Short-Term Outlook report published on May 29.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Refined oil product output in France is rising as demand returns, with the Total-operated Grandpuits refinery coming back online and two ExxonMobil-operated refineries boosting runs.
The 100,000-b/d Grandpuits facility, located near Paris, was initially due back online in March after a month-long maintenance period, but the refinery remained offline due to slumping demand as France undertook its lockdown to combat the coronavirus disease 2019 (COVID-19) pandemic.
"I can confirm that Grandpuits has started coming back online," a spokeswoman for Total said Tuesday.
French prime minister Edouard Philippe outlined the government's plan for easing COVID-19 lockdown measures on May 11, ending almost two months of travel restrictions for France's population of 67 million.
ExxonMobil's 120,000-b/d Fos refinery, based in the south of France, has joined the company's 233,000-b/d Gravenchon plant in "adapting to the demand" for oil products in the country, where lockdowns are easing and consumption increases, according to a company spokeswoman.
The Gravenchon refinery increased runs last week as the company informed local residents that units were being brought back into operation. ExxonMobil declined to offer figures regarding exact throughput at the refineries.
Total's 100,000-b/d Feyzin refinery is seeing more worker activity on site but remains offline, local sources said. The French oil major began a big turnaround at Feyzin on February 14, with the work scheduled to last several weeks at a cost of 80 million euros, but maintenance was stopped on March 20 due to the COVID-19 pandemic.
Refinery maintenance scheduled before the COVID-19 pandemic could encourage some operators to boost output, according to IHS Markit principal downstream research analyst Eleanor Budds.
"Refineries are ramping up, not just in France, and yet margins and crack spreads are very low," said Budds. "French refineries may have more leeway than in some other countries, as several were shut for maintenance or outages even pre-COVID crisis, so storage tanks may not be as full as elsewhere. We expect gasoline and passenger diesel demand to be at around 10% lower than 2019 levels for July-August, mainly due to increased home working and job losses. Road travel will benefit from less flying this summer, and from more discretionary driving to avoid public transport use."
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, anthony.lane@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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MEXICO CITY -- Mexico's driving levels for the first week of June reached 60% of the activity reported at the beginning of the year, almost twice the level reported by Apple for mid-April.
Driving activity has slowly recovered since the week ended April 12, when driving levels were 35% of the baseline driving levels reported by Apple for the third week of January.
The recovery in driving activity coincided with the end of Mexico's Safe Distancing Campaign to contain coronavirus disease 2019 (COVID-19), and the start of new normality with restricted economic activity under a traffic light system.
Pemex CEO Octavio Romero Oropeza reported on Friday that his company sold up to 620,000 b/d of gasoline during the first week of April, a year-over-year (YOY) increase of 3%.
In comparison, Romero said Pemex's gasoline sales fell close to 50% YOY during the first week of May.
Volumetric data from 6,000 retailers collected by Queretaro-based consultancy firm URSUS Energy show Mexico's gasoline demand is down 34.8% during the first week of June.
According to the data shared with OPIS by URSUS, Mexico fuel sales recovered 35% during the first week of June versus the first week of April.
URSUS Energy estimates that, based on volumetric data, Pemex retail fuel sales dropped 43.2% during May.
The last time Mexico had a similar driving activity level of 60% from the baseline level was in the week ended March 22, when it sold 797,000 b/d of gasoline, according to data from Mexico's Energy Secretariat (SENER).
Late March was an atypical time as large numbers of Mexicans filled cars, taking advantage of lower fuel prices.
Multiple states reported driving activity levels at over 70% of baseline levels during the first week of June: Aguascalientes, Baja California, Campeche, Chihuahua, Coahuila, Colima, Durango, San Luis Potosi, Sinaloa, Sonora, Tamaulipas, Tlaxcala and Zacatecas.
The highest recovery in driving activity has been in the northern states of Tamaulipas (96.8%), Coahuila (93.8%), Chihuahua (90.1%) and Durango (89.6%).
Among the large metropolis, driving activity in Mexico City recovered to 40% from baseline levels versus 27% in the week ended April 12. Guadalajara and Monterrey reached driving activity levels of 64% and 70%, respectively versus baseline levels, up from 31.8% and 32% in mid-April.
Gasoline demand seems to be recovering despite the number of new COVID-19 cases: They reached a new record Thursday with 4,462 new cases in 24 hours, an increase of 60% compared with the same day a week prior.
Mexico has had the lowest number of tests positive for COVID-19 among countries in the Organization for Economic Co-operation and Development makes, which makes market observers think the outbreak is worse than reported by the government.
According to an investigative report by Mexico City-based magazine Nexos, found that Mexico City released 20,900 death certificates during April and May, of which 7,196 mention COVID-19 as the cause of death, 5,900 as respiratory insufficiency, and 5,540 as atypical or viral pneumonia.
The death rate related to COVID-19, pneumonia, and respiratory issues is three times higher than the figure reported by health authorities for Mexico City.
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--Daniel Rodriguez, drodriguez@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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The petrochemical sector in northwest Europe continued to cut its intake of LPG feedstock in May as propane values maintained significant premiums to rival feedstock naphtha, leading to a slash in LPG import flows from the U.S.
Around 412,000 metric tons of LPG cargo was imported by coastal crackers last month in northwest Europe, dropping 20% from 513,000 mt in April and 35% from 630,000 mt in March, in addition to a 26% decline from May 2019 at 554,000 mt, according to OPIS tracking. Only 30,000 mt of U.S. LPG was imported into northwest Europe last month, compared with 10 times that volume at the same time last year.
CIF ARA propane prices extended its two-month run holding a premium to CIF NWE naphtha, with propane/naphtha trading at +$53/mt at the start of May, down from a high of +$131/mt recorded on April 21, but still atypical going into the summer months when propane usually trades at a discount due to the lack of heating demand. By comparison, the propane/naphtha spread was minus $139/t in May 2019. A petrochemical producer with feed-flexible coastal facilities in the Netherlands and Spain made repeated propane cargo resale attempts last month.
Premiums for large field-grade CIF NWE butane cargoes over naphtha were less drastic, starting May valued at 106% of CIF NWE naphtha before easing back to 87% by month-end.
Demand attrition for finished goods in the petrochemical chain due to coronavirus disease 2019 (COVID-19) gathered pace in May, with Dow Chemical among other producers announcing the idling of some downstream chemical units (see OPIS alert April 30, 2020).
Overall northwest Europe LPG cargo trade reduced by 8% from April to 730,000 mt, and was sharply down from 1.03 million mt at the same time last year.
Intake into the retail and refining sector was up by 35,000 mt to 165,000 mt.
Petrochemical operators relied more on local North Sea supply, with 81% of their May LPG intake from North Sea countries Norway and the U.K., while 11% came from the Russian Baltic region and 8% from the U.S. East Coast.
Imports of U.S. LPG were impeded by the closure of arbitrage opportunities.
U.S. propane prices had remained relatively strong amid signs that U.S. refiners, blenders and gas plant operators were scaling back output of propane, seeing the transatlantic Mont Belvieu and CIF ARA front-month spread falter to minus $32/t from minus $46/t over the course of May.
Offers for two Very Large Gas Carrier (VLGC) size cargoes from the U.S. into the CIF ARA market, one for full propane and another 3:1 propane-butane split, were not placed and the cargoes were seen moving to the Pacific region instead.
LPG exports out of northwest Europe were steady month on month at 160,000 mt, with cargoes moving to the Baltic, North Africa, Turkey and to India. However, exports flows to east-of-Suez destinations ceased after the shipment to India in early May as the CFR Asia market lost momentum, resulting in the balance month East/West spread shrinking from plus $65/t to plus $41/t over the course of May.
Looking ahead, LPG has come back into favor as a petrochemical feedstock as naphtha prices have rebounded harder on rising Brent crude oil values. The propane/naphtha spread tipped negative for the first time in two months to minus $6/t on May 26, and has since deepened to minus $24/t at last look, spurring a petrochemical producer to resurface seeking propane cargoes.
Gain greater perspective on global spot prices for naphtha, propane and butane.
OPIS developed the pricing in our Europe LPG & Naphtha Report to reflect the market’s desire for an unbiased methodology and accurate spot price benchmark in northwest Europe and the Mediterranean.
--Reporting by Dermot McGowan, dmcgowan@opisnet.com; and Inge Erhard, ierhard@opisnet.com;
--Editing by Karen Tang, ktang@opisnet.com
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Asian petrochemical producers plan a modest increase of liquefied petroleum gas (LPG)cracking in July from the lower levels intended this month, while gas usage will grow further in August when demand for heating fuels in the northern hemisphere eases, according to a poll.
The growth, however, is unlikely curb naphtha demand as margins from the feedstocks remain attractive amid a recovery in ethylene markets, analysts and traders said.
Cracker operators, which can use naphtha and LPG, are set to input 310,000 mt of the gas in July, up 1.3% from a revised 306,000 mt for this month, according to an OPIS poll that concluded on June 5.
The petrochemical manufacturers had planned to crack 350,000 mt in June, according to the previous survey published on May 13. They used 321,000 mt in May, lower than initial plans of 357,000 mt.
"We do expect August cracking volume to increase as compared to the previous few months with the softening in LPG prices. Summer is in full swing in August so demand for LPG as heating fuel should be seasonally low during that time of the year, easing market balance," said April Tan, IHS Markit associate director in Singapore.
"Overall naphtha economics is still attractive as compared to LPG cracking during August, so demand for naphtha into cracking is expected to continue," Tan said. OPIS is a unit of IHS Markit.
Naphtha demand in Asia is expected to increase to 3.769 million b/d from 3.684 million b/d in July and 3.452 million b/d in June, according to Tan.
Ethylene production costs and margins from naphtha were better than LPG, according to IHS Markit Asia Light Olefins Weekly report published on May 29.
The cash cost of steam cracking in Northeast Asia using naphtha was estimated at $264/mt as of May 21, generating a margin of $366/mt, the report showed.The costs of cracking LPG was almost double at $413/mt and the margin was $217/mt.
Naphtha cracking economics were better than LPG with the propane/naphtha ratio assessed at 99.1% on June 4, according to OPIS data. The ratio on April 15 shoot up to 179.3% on April 15, the highest on the data, cutting LPG cracking, as strong demand from India and Indonesia on lockdown measures to curb coronavirus 2019 (COVID-19) lifted gas prices.
Petrochemical producers typically find it more attractive to crack naphtha instead of LPG when the ratio rises above 90%.
Strong naphtha demand, as well as tight supply with lower arbitrage flows and refinery turnarounds, will support prices. CFR Japan on June 3 rose to $343.750/mt, the highest since March 6.
Ethylene market sentiment in Asia strengthened on limited offers and increasing demand in the key polyethylene sector, according to the IHS Markit report.
A petrochemical producer in Northeast Asia raised cracker runs to full in June from around 90%, given the strong market, an official at the company said.
"A rebound in ethylene markets amid an economic recovery prompted us to gradually increase the runs, although we doubted how long the recovery will continue," said the official.
The Asian Manufacturing PMI, compiled by IHS Markit, edged up to 44.7 in May from 43.9 in April, the lowest since March 2009, indicating regional manufacturing condition is better even though it's not expanding.
Methodology: OPIS collects Asian petrochemical companies' plans for the current month and the next month, as well as actual cracking volume in the previous month. OPIS, a unit of IHS Markit, checks if any manufacturers revise their plans for the current month and if any manufacturers crack more or less than initial plans in the previous month. OPIS contacts feedstock procurement officers of each companies for the survey by phone, email or messengers in the last week of previous month or the first week of the current month. OPIS surveys 16-20 companies a month.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com, Masayuki Kitano Masayuki.Kitano@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Turkish refiner Tupras will operate at an 80-85% capacity utilization rate from July at its refineries in Izmit, Izmir Kirikkale and Batman in Turkey, the company said in a recent investor presentation.
The refineries, which have a total crude processing capacity of over 630,000 b/d, are being ramped up as Tupras expects economic activity to resume as normal in August following a slowdown due to the coronavirus disease 2019 (COVID-19) pandemic, the company said in May.
Tupras expects robust diesel and high sulfur fuel oil cracks for the rest of the year, although its outlook for jet and gasoline cracks is less positive.
The company revised its 2020 production forecast down to 24 million metric tons from 28 million mt, and it has also lowered its sales estimates from 29 million/mt to 25 million/mt due to lower demand.
"It has been assumed that COVID-19's negative impact on crude and petroleum products demand will begin to decrease by June and normal economic activity will resume starting from August," said Tupras.
A six-week maintenance program will be carried out at the 230,000 b/d Izmir refinery's fluid catalytic cracking unit in the fourth quarter this year.
Tupras will resume production at its 230,000 b/d Izmir refinery on 1 July, which accounts for 40% of its crude oil processing capacity, the company said in a recent filing posted on the Public Disclosure Platform (KAP) website.
Production stopped temporarily at the refinery on May 5 due to falling demand for oil products amid travel restrictions to prevent the spread of COVID-19, Tupras said.
Get daily expert analysis of the Northwest Europe and Mediterranean jet fuel, ULSD and gasoil markets with OPIS Europe Jet, Diesel & Gasoil Report Try it free for 21 days
--Reporting by Stacy Irish, stacy.irish@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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The Asia gasoline market is expected to strengthen further with its margin poised to turn positive amid tighter supply due to lower Chinese exports and reduced refinery runs just as demand is growing on the back of looser lockdown measures, analysts and traders said.
The benchmark Singapore 92 RON crack to Brent, or refining margin, gained $1.313/bbl on Wednesday to minus $0.217/bbl, the strongest since May 21 when it was at minus $0.156/bbl, according to OPIS data.
The crack was mostly negative since March 13 as governments locked down entire countries or major cities to curb the coronavirus disease 2019 (COVID-19), eroding gasoline demand. On April 14, the crack fell to minus $12.986/bbl, the lowest on OPIS records going back to July 2014.
The refining margin has improved since then, briefly turning positive in May, as authorities eased social distancing measures against the pandemic, helping demand recovery amid tight supply.
Refineries in major gasoline exporting countries such as China reduced exports in the past month to meet growing local consumption, the sources said. Gasoline importers including the Philippines and Australia increased purchases as local refiners cut runs or shut facilities for maintenance.
"The key is a slash in Chinese exports. Other refineries were under turnarounds and cut runs. That came when some countries needed to import more until their refineries are normalized," said a Singapore-based trader, expecting further strength in the regional gasoline markets.
Traders booked just six tankers to load 205,000 mt in May from China, less than a third of the 675,000 mt in April, shipping fixtures showed. In April, Chinese exports surged 62.1% on-year to 1.90 million mt, according to the customs data.
In contrast, some countries such as the Philippines increased imports. Its two refiners, Petron Corp. and Pilipinas Shell Petroleum Corp., shut their plants for turnaround last month.
Petron Singapore Trading, which buys for the Philippines market, sought up to 150,000 bbls of 87 RON and/or up to 150,000 bbls of 92 RON for loading on July 1-6 via a tender this week.
Last month, Petron closed a tender to buy 200,000 bbls of 87 RON and/or 100,000 bbls of 92 RON for loading on June 5-10, as reported earlier, although its results were not known.
Demand recovery in Asia prompted traders to ship gasoline and its components from Europe where consumption was relatively weaker, market sources said.
Traders have booked five tankers to load 327,000 mt of gasoline and reformate for loading in June so far mostly from Northwest Europe, shipping fixtures showed.
For May-loading, traders chartered three tankers to load 167,000 mt to Singapore and China.
The rising flows from the West as well as the possibility of a rebound in Chinese gasoline exports may pose risks to the Asian markets, but strong demand could mitigate the supply increase, traders said.
"It is not a time to see corrections yet since the current demand was solid, but supply was tight," another Singapore-based trader.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Plans by the Chinese provincial Shandong government to build a mega refining-cum-petrochemical complex is unlikely to lead to a glut of oil products due to its high integration and the probable closure of several teapot plants as part of a consolidation exercise, analysts and trading sources said.
The Yulong project has been in the making for years. Last September, details emerged for an 800,000 b/d refinery to be built in two phases with the first 400,000 b/d to be integrated with two 1.5 million mt/year ethylene plants, according to the Shandong provincial and Jilin city governments.
The authorities began a second public review of its environmental impact assessment (EIA) as of March 31, 2020, IHS Markit reported in their April short-term outlook on the China Crude Oil Markets.
"The extent of its impact will hinge on whether the smaller, less competitive teapots close in tandem with Yulong's upcoming capacity," said one trading source that has dealings with refiners in that part of China.
The Yulong project will be the most sophisticated yet in the string of mega refineries that have come onstream in the past year including the 400,000 b/d each of Hengli Petrochemical and Zhejiang Petrochemical (ZPC), according to IHS Markit.
"The combined yield of transport fuels of Yulong can be as low as 17%," said Feng Xiaonan, IHS Markit analyst in Beijing and one of the authors of the report, adding, "If enough teapots are closed down, there will be very limited incremental supply of transport fuels since these teapots mostly produce fuels and very limited chemicals."
Ten independent refineries, with a combined 560,000 b/d capacity, have so far signed up to swap their existing refining assets into equivalent equity shares in the newly proposed refinery, according to the IHS Markit report.
The provincial government announced on Feb. 11 that it will start work to close down four of the participating refineries in 2020, namely Zhonghai Fine Chemical, Yuhuang Shengshi, Binyang Gasificaiton and Kinshi Bitumen, which have a combined 254,000 b/d processing capacity, the IHS Markit report showed.
"Considering that the COVID-19 outbreak has already put mounting pressure on employment and local economic growth, we believe it is probable for the government to postpone refinery closures in order to maintain stability," they said in the report.
Feng said on Wednesday that the project still faces a lot challenges and uncertainties.
On Tuesday, Reuters news agency reported that the National Development & Reform Commission (NDRC) gave initial approval for the $20 billion project, allowing Shandong province to start planning for construction for around an end 2024 start, citing sources with knowledge of the approval.
The Yulong complex is designed to convert over 60 % of a barrel of crude into petrochemical products and feedstocks through a combination of hydrocracking and intensive catalytic cracking technologies, IHS Markit said.
"If such design is carried through, China will be able to take its crude-oil-to-chemicals (COTC) achievements one big step forward from where the operating Hengli and ZPC currently stand, consolidating the country's world leading position in the realm of refining and petrochemical integration," it said in the report.
Market sources said the success of the project also depends on how well these smaller teapot refinery owners work within a mega company.
"I do believe that the smaller refineries will benefit by but within the whole structure of the new entity, they may not be satisfied when they are used to be the big boss making all the decisions," another trading source said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Sharply lower demand from U.S. West Coast refiners has prompted global crude majors to cut their oil production in Alaska to their lowest since 1977, while favorable pricing economics for Alaska North Slope (ANS) could open up a unique opportunity for the medium sour crude for export to Asian markets, according to independent research firm Morningstar.
Despite recent oil production declines, ANS crude's new export outlet to Asia and an expected recovery in crude prices after the unwinding of the coronavirus disease 2019 (COVID-19) pandemic should justify longer-term investments by majors in Alaska, said Sandy Fielden, director of oil and products research at Morningstar in Austin.
Alaska crude output fell below 400,000 b/d in the first week of June, on track for its lowest since July 1977, which has dropped by one-fifth from the 500,000 b/d in early March, and a record 2 million b/d in 1988, according to data from the Alaska Department of Revenue and the U.S. Energy Information Administration.
The pace of the production cutback could accelerate in June, as U.S. major ConocoPhillips Co., said in late April it would voluntarily cut oil production by 100,000 b/d in Alaska for the month of June as part of its curtailment in response to weak oil prices.
The rapid production collapse has not only been a response to lower prices but also operational constraints, said Fielden. The 2-million-b/d Trans-Alaska Pipeline, or Taps, that connects the North Slope oil fields and the Valdez shipping terminal has prorated in April to prevent a storage overflow at Valdez, effectively requiring producers to shut in oil wells in times of weak refiner demand.
Economic run cuts by U.S. West Coast refineries due to COVID-19 have sharply reduced demand for ANS crude, as nearly 4 in every 5 crude barrels produced in Alaska are consumed by refineries in California and Washington state, according to Fielden, citing U.S. Census and state data in 2019.
In addition, an arbitrage pricing window between ANS and Asian markets has opened since the start of April, with Middle East crudes delivered to Asia trading at an average of $5/bbl above ANS so far in Q2 2020, resulting in three rare cargoes of ANS exported to China between late April and May, Fielden said.
Far cheaper ANS than Mideast crudes suggests ANS is competitive in Asian markets even with higher freight charges with the use of U.S. flag vessels, which are required to export Alaskan crude via Taps.
"The ANS pricing advantage should continue to provide opportunities for exports for several reasons that could alleviate Taps' operational constraints and allow producers to ramp up output again in the second half of 2020," said Fielden.
ANS export is now more likely due to a combination of China's growing crude demand after COVID-19 lockdown, output cuts agreed by OPEC+, competitive freight costs to consume ANS versus U.S. Gulf Coast around South America, and Asian refiners favoring the medium sour ANS versus lighter shale crudes, according to Fielden.
A 2018 study by IHS Markit suggested that the Alaska North Slope could re-emerge as a major source of U.S. energy production, with crude oil output potentially increasing as much as 40% in eight years, due to new discoveries and higher investment by majors.
IHS Markit is the parent company of OPIS.
New wells expected online this year and a pending sale of BP's Alaskan assets to Hilcorp, a Houston-based producer which specializes in exploiting mature fields to revive ANS output in coming years, could boost production, Fielden said.
Fielden said that the export market for ANS crude to Asia now justifies longer-term investment, provided that prices recover above $50/barrel. As the COVID-19 crisis unwinds, major oil companies and larger, financially secure producers need to find investment horizons that they are comfortable with.
"If that horizon is short term in response to an uncertain price- and demand scenario then shale plays are more attractive. If the horizon is longer term based on confidence that oil has a 30- year future, then bigger plays like Alaska should be favored," he said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Frank Tang, ftang@opisnet.com,
--Editing by Denton Cinquegrana, dcinquegrana@opisnet.com
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Monthly demand for transport fuel in Europe plunged year on year in April, amid travel restrictions to mitigate the spread of the coronavirus disease 2019 (COVID-19) pandemic, according to official data.
Gasoline consumption in Spain, which went into a full lockdown on 14 March, fell to 97,000 metric tons in April, 77.8% down from April 2019, according to data from the Corporacion de Reservas Estrategicas de Productos Petrolífero (CORES). Consumption of 10-ppm ultra-low-sulfur diesel fell by 55% to 887,000 tons over the same period, said hydrocarbon industry information provider CORES.
In Italy, demand from the wholesale market for gasoline in April fell to 164,000 tons, down by 73.4% from the same month last year. Demand for 10-ppm diesel decreased by 59.9% to 804,000 tons from April 2019, according to data from the country's Ministry of Economic Development. Deliveries of gasoline in France were down by 70.2% and 10-ppm diesel by 61.5% in April compared to year-ago-levels, according data from to industry group L'Union Francaise des Industries Petrolieres (UFIP).
This plunge in demand was reflected in the collapse of spot market prices for key European refined oil products, according to OPIS analysis of crack spreads, a rough measure of refiners' profitability.
Gasoline Eurobob barges prices, in the Amsterdam-Rotterdam-Antwerp trading hub of northwest Europe, saw crack spreads widen to negative $8.37/bbl in April, from negative $2.85/bbl on average in March, before recovering to an average of negative $1.75/bbl in May.
Prices for 10-ppm diesel barges were more resilient over this period, falling to an average $5.25/bbl in April and then down to an average $1.64/bbl in May, from an average $11.34/bbl in March, according to OPIS data.
Jet fuel deliveries in France fell by 87.5% in April, according to UFIP. Prices have kept relatively steady over April and May as passenger flights remain grounded, with crack spreads for FOB jet barges, basis Flushing, Amsterdam, Rotterdam, Antwerp and Ghent averaging minus $4.85/bbl in April and minus $4.06/bbl in May. This is sharply down from an average of plus $4.59/bbl in March, OPIS data show.
Still, as countries begin easing travel restrictions, data for May suggests the beginning of a recovery in demand, even as gasoline and jet fuel continue to be the most severely affected transport fuels.
In Italy, total oil consumption is expected to drop by 35% in May, compared to an overall 44.5% slump in April, according to data from Unione Petrolifera (UP) last month.
Deliveries of oil products in Spain from terminals belonging to the Compania Logistica de Hidrocarburos (CLH Group) into the domestic market have similarly fallen by a lower magnitude in May compared with May 2019, company data show.
Gasoline deliveries fell by 56.3% and 10-ppm diesel dropped by 38.3% in May compared to the same month a year ago, CLH Group said on Monday. This compares with April declines of 78.6% for gasoline and 56.6% for diesel.
By contrast, gasoline sales in Sweden, which has not imposed a countrywide lockdown, fell by only 16% in April from the same month last year to about 209,700 cubic meters. Diesel demand declined over the same period by only 5% to about 501,200 cubic meters, according to preliminary data from industry group Svenska Petroleum and Biodrivmedel Institutet (SPBI).
April data for the U.K. and Germany was not available at the time of publishing.
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--Reporting by Paulina Lichwa-Garcia, paulina.lichwa-garcia@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Chinese buyers paid a premium for their jet fuel cargoes against Singapore prices for the first time in more than six months in a sign of improving market fundamentals as more airlines take to the sky and production is still curtailed, trading sources said.
China Aviation Oil (CAO) awarded its latest buy tender for late-June and early-July delivery at premiums of $0.50-$1.00/bbl to Singapore prices on CFR basis, the sources said.
The tender was for 40,000 mt for June 28-30 delivery to Tianjin and 25,000 mt for July 1-3 delivery to Huangpu. The winner of the tender was not known.
"The premium paid for CFR cargoes given the lower freight rates now indicates that jet fuel market is strengthening," a trader said.
For example, freight on the Singapore-Hong Kong voyage for a medium-range tanker (MR) rose to as much as $1.1 million in early May, but has since tumbled to around $310,000 in June.
The last cargo CAO bought at a premium was for Jan. 5-8 delivery to Huangpu at premiums of $1.70/bbl, OPIS records showed. Over the past months differentials for similar a CFR tender by Taiwan's CPC Corp fell to a discount of $1.00/bbl for mid-June arrival.
"The tender was probably picked up by a Singapore-based firm," according to a trader.
Shipping fixtures showed that Mitsui Energy Trading Singapore (METS) booked the Pacific Jewel to load 30,000 mt of jet fuel from South Korea on May 26 to Shanghai at an undisclosed rate.
CAO officials were unavailable for comment on the tender.
Demand for jet fuel is picking up in China as it eases measures on curbing the coronavirus disease 2019 (COVID-19).
The Civil Aviation Administration of China (CAAC) announced that it will open an application channel for "green channels" for chartered flights to their airports, according to a CAAC notice.
Countries that are currently eligible to apply are Singapore, Japan, Germany, France, Britain, Italy and Switzerland, the notice states.
Such green channel will allow travelers to enter China with minimal health screening and quarantine measures.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report. Try it free for 21 days
--Reporting by John Koh, John.Koh@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Traffic around the United States continues to climb back toward levels seen before the start of the coronavirus disease 2019 (COVID-19) pandemic but still lags behind what would normally be seen at the start of the busy summer driving season, according to the latest data from research firm Inrix.
Personal travel during the week ending May 29 was only 16% off where it had been in February, prior to states taking efforts to contain the pandemic.That's compared to 19% off pre-pandemic levels that was seen a week earlier.Longhaul truck traffic was off 13.5% compared to pre-COVID levels.
Six states -- Wyoming, South Dakota, Montana, Idaho, Alaska and Utah -- have all seen personal traffic increase past where it had been prior to pandemic, while another 16 states are seeing a deficit of less than 10%. Hawaii continues to lag the furthest from February levels, off 49%, while three states are seeing personal traffic off by 30% to 39%. Ten states are 20% to 29% off pre-COVID levels, while 13 are seeing personal travel 11% to 19% behind where it was before the start of lockdowns.
Personal travel last week also increased in 88 of 98 metropolitan areas Inrix tracks. New York and Miami both continue to see personal travel off 40% from pre-virus levels, the largest decrease among any metropolitan areas.
While the travel data shows the impact of the recent easing of stay-at-home orders, Inrix warns the weekly data doesn't paint a clear picture of the virus'ongoing impact on travel since the comparison is not seasonally adjusted. Such a seasonal adjustment would most likely show the virus still having a significant impact on traffic, since the Federal Highway Administration data shows daily average travel in May 2019 was about 15% higher than daily average travel in February of that year, the research firm said.
OPIS DemandPro data for the week ending May 23 showed gas stations around the nation sold an average 31.8% less fuel than during the same time in 2019, while Inrix data for the week showed traffic off 19% from February levels.
It's likely travel will continue to lag behind normal levels in the coming weeks, as some people skip vacations and stay home even as states continue easing regulations.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Steve Cronin, scronin@opisnet.com;
--Editing by Michael Kelly,
michael.kelly3@ihsmarkit.com
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Growing ground and air traffic flows in South Korea are raising local transportation fuel consumption, industry officials said, prompting refiners to cut exports due to domestic plant maintenance works.
The number of vehicles on highways in May rose 5.7% to an average 4.5 million units a day from 4.3 million in April, according to data from the Korea Expressway Corp.
Domestic flights last month increased with visitors to Jeju island, a major domestic tourist spot, increasing by 32%, local media reported. The air route between Seoul and the resort island is the busiest in the country.
At the same time, Korean Air and Asiana Airlines, the country's two largest carriers, resumed some international flights, according to the reports.
"Consumption of gasoline and diesel rose to about 90% of levels in the previous years, while demand for jet fuel recovered to around 60%," said an official at a major refinery, asking not to be identified.
The coronavirus disease 2019 (COVID-19) had hit South Korea hard earlier this year, eroding fuel consumption.
In April, jet fuel consumption hit a record low of 730,000 bbls, while gasoline demand fell to 6.8% to 6.581 million bbls, data from the Korea National Oil Corp. (KNOC) showed.
Gasoil consumption, which is also a main road fuel with about 80% of sales ending up in the driving pool last year, slumped 16% to 12.982 million bbls in April, the lowest since October 2019.
The declines were reversed after the government relaxed its social distancing measures on May 6, analysts and refinery officials said.
The rebound came as local refiners had cut runs and shut plants for turnaround, resulting in lower exports.
South Korea's May exports of petroleum products in value tumbled 69.9% on-year to $1.06 billion, according to data from the Ministry of Trade, Industry and Energy on Monday. A ministry official said volume data was not available.
"Fewer spot cargoes for June-loading were heard," said a Singapore-based trader. "July-loading cargoes are not that much either."
Traders booked eight tankers to lift 280,000 mt of products such as gasoline and ultra-light sulfur diesel (ULSD) in June, while 26 vessels were chartered to load 910,000 mt in May, according to shipping fixtures.
Last month, SK Energy, the nation's largest refiner idled its 260,000 b/d No. 5 CDU and other facilities including the 57,000 b/d No.1 residue fluidized catalytic cracker (RFCC) at the 840,000 b/d Ulsan refinery for scheduled turnaround, as reported earlier.
The works are set to conclude on June 22.
Still, an analyst said it is premature to expect a sharp rebound in consumption of transportation fuels, especially jet fuel.
"We may not see a real recovery until international flights increase. Some travel agencies started offering overseas trip programs, but only for trips from August," said the analyst.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report. Try it free for 21 days
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Uncertainty continues to hang over the maintenance plans of British refinery operators, who have been juggling the demands of government, low refining margins and the practicalities of undertaking turnarounds during a pandemic.
The tricky calculations facing some U.K. refiners are best embodied by a debate swirling around the 210,000-b/d Petroineos-operated Grangemouth refinery.
The refinery was due to come offline along with the nearby Ineos-operated petchems site in April, but sources in the area said in March that all the works would be postponed amid the onset of the coronavirus disease 2019 (COVID-19) pandemic.
Those same sources now say that Petroineos is deliberating whether to shift the postponed maintenance to either the summer - seen as the most likely option -or as late as the second quarter of 2021, with the risk of a second big wave of winter coronavirus infections weighing on considerations.
One source in the area told OPIS last week: "It's still being debated at the moment as to whether it could be put off until later on in the year or even next year."
Sources with knowledge of Petroineos' plans said delaying the turnaround for a year was possible, but pointed out that some maintenance on ethanol-producing units planned for April was eventually only deferred for a matter of weeks.
"Because of the coronavirus pandemic and the fact that ethanol is one of the main components of hand sanitizer, it has been kept going," a source withaccess to Grangemouth told OPIS earlier this month. "It's needing some maintenance," the source said at the start of May. The work was completed within two weeks, the source later said.
Further uncertainty surrounds the fate of the £350-million combined heat and power plant at the Grangemouth site that was due to begin construction in the fourth quarter of this year.
OPIS sources in the area say that temporary workers due on site in advance of the work were told their services were no longer required.
The refinery's financial viability, an issue that has dogged Grangemouth in the past, reared its head again earlier this month, when Petroineos was widely reported by the British media to have applied for an emergency government loan of up to £500 million.
"With people following government advice to stay at home, demand for road and jet fuel has dropped significantly," the company said in a statement reported by IHS Markit, the parent company of OPIS. "As a responsible operator of Scotland's only refinery, Petroineos is in regular discussion with the Scottish and U.K. governments on a variety of matters."
Asked whether there was concern among the workforce about what would happen to the refinery, one worker representative said: "There are discussions ongoing with the U.K. and Scottish governments. I don't think there is a huge fear that the refinery is going to shut."
The turnaround plans of Phillips 66, the operator of the 210,000-b/d Humber refinery, which lies on the east English coast, were also nixed by the pandemic.
OPIS revealed in March that a turnaround planned at the refinery for the April-June period had been postponed until September, according to sources in the area.
However, some unit work is ongoing, the operator told OPIS this week when asked if the refinery's fluid catalytic cracker was offline for maintenance.
"There is planned maintenance work currently underway at the Humber refinery," the company told OPIS in an e-mailed statement. "Details regarding the specific units involved and the duration of the work are considered proprietary."
The most unclear refinery maintenance schedule belongs to the U.K.'s largest refinery, the ExxonMobil-operated 270,000-b/d Fawley plant.
The operator had previously given assurances to local government authorities that it would not undertake big planned maintenance work during the construction of the $1.5 billion Fawley Strategy (FAST) project, assuaging authorities' concerns related to the ability of road infrastructure to cope with increased heavy vehicle traffic.
Almost all the physical work on FAST -- involving upgrading existing units as well as the construction of a hydrotreater and hydrogen plant that would boost diesel output by 38,000 b/d -- has since been put on hold. Sources with longstanding knowledge of the FAST project told OPIS earlier this month that the project's mechanical work might not resume until 2022.
ExxonMobil has not answered queries regarding whether, in light of FAST work being postponed, it still considers itself bound by those assurances offered to local authorities not to undertake major maintenance work this year.
Another question hanging over Fawley and other British refineries concerns whether the U.K. government has intervened to encourage operators to stay online during the pandemic and could make a similar intervention in the future.
Sources at Fawley said in March that the U.K. government had insisted to ExxonMobil that it must keep the refinery running "at all costs" during the COVID-19 pandemic, even as refining margins for products such as gasoline entered double-digit negative territory.
The British government has been holding regular conference calls with the refinery's manager in order to receive updates about the plant's status, sources at Fawley have told OPIS.
It is notable that no U.K. refinery has been offline during the pandemic, in contrast to the situation in France and other European countries.
Refinery operators contacted by OPIS have batted away inquiries related to any government demand or encouragement to stay online.
"Our industry is considered a critical sector," was all a spokesman for Phillips 66, the operator of the Humber refinery, would say on the subject.
That phrase was also used by a government spokesman when OPIS asked if refineries had been pressed to stay up and running.
"As a critical sector, workers in the oil and gas industry have continued operations while taking the necessary precautions," a spokesman at the Department for Business, Energy and Industrial Strategy told OPIS. "The government has been engaging with the UK's oil refinery operators, as well industries across all sectors, during this period."
"The oil, gas and electricity sectors are listed as critical sectors, meaning workers in this industry are key workers and continue to work to keep Britain powered," the government said.
The maintenance plans of the U.K.'s two other large refineries -- the Essar-operated 200,000-b/d Stanlow refinery in northwest England and the Valero-run 220,000-b/d Pembroke plant in Wales -- have been less affected by the pandemic, although runs at the refineries have been reduced.
Essar is not planning a major maintenance at Stanlow until February 2022, OPIS revealed at the start of this year. Sources briefed on the operator's plans say that rolling individual unit maintenance will instead take place until 2022.
A spokesman for Essar told OPIS this week that the refinery's fluid catalytic cracker, which boosts gasoline output, came back online in the first half of April. Essar also had second-quarter work penciled in for Stanlow's hydrofluoric acid and sulfur recover units, sources with familiar with the refinery's work schedule say.
Valero's next big maintenance at Pembroke is not scheduled until the second quarter of next year, say sources with knowledge of the operator's plans.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Jessica Marron, jmarron@opisnet.com
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Japanese crude oil imports fell to a near two-year low in April as refiners cut runs amid measures to contain the coronavirus disease 2019 (COVID-19) that eroded fuel consumption, but purchases are likely to hit a low this month before rebounding, according to government data and market sources.
It bought 13.17 million kl, or 2.76 million barrels a day (b/d), the smallest since June 2018, according to data from Ministry of Economy Trade and Industry (METI) on Friday. The April imports were down 9% from a year earlier.
Purchases from the Middle East slumped 7.1% on-year to 11.93 million kl with that from Saudi Arabia, its top supplier, down 6.5% to 4.78 million kl, the data showed. Imports from Russia shrank to 222,225 kl, a quarter of the 812,017 kl from a year ago.
Crude purchases may gradually reverse course from June, given an expected rebound in consumption and the record low throughput this month, analysts said.
"Crude imports may have fallen further in May, given lower crude runs. But it may rebound from June as refiners will raise throughput in line with demand recovery," said Matthew Chew, principal researcher at IHS Markit in Singapore.
Japan's crude imports are forecast to increase from 2.3-2.4 million b/d in May to 2.5 million b/d in June, 2.7 million b/d in July and 2.85 million b/d in August, Chew said.
Japan on May 25 lifted the state of emergency over the COVID-19 in all prefectures including Tokyo, as reported earlier.
That will help demand gradually recover and could prompt refiners to seek spot crude oil after they were informed of larger-than-expected-cuts to their June-loading term supplies from Middle East producers, the PAJ president said last week.
Prime Minister Shinzo Abe on April 7 declared the state of emergency in Tokyo and other areas to contain the COVID-19 and expanded the measure to the whole country on April 17.
Domestic oil product sales in April fell 14.5% on-year to 11.50 million kl with jet fuel consumption tumbling 76.2% to 104,897 kl and gasoline down 22.7% to 3.17 million kl, the METI data showed.
Refiners processed 12.34 million kl of crude oil in April, down 17.3% from a year earlier, according to the METI data.
Last week refinery runs slumped to 56.1% of the nation's total 3.52 million b/d capacity, the lowest on OPIS records of the Petroleum Association of Japan (PAJ) data going back to January 2014.
Over the course of the week operable capacity was down another 238,185 b/d to 2.78 million b/d as units were shut, the PAJ data showed.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Distressed North Sea crude is once more finding a home in East Asia, particularly China, as refiners there increasingly look to unsold cargoes to fill the gap left by the OPEC+ output cut and production shut-ins, according to trading sources and shipping data.
After a lapse of about two months – when cheaper Urals over took as the crude of choice to Asia buyers – North Sea staples such as Johan Sverdrup, Forties and Grane are making a comeback as their pricing economics improved in the face of supply shortfalls elsewhere, market sources said.
They said unsold North Sea blends, especially Forties that’s been floating on board tankers, are set to make the long voyage East in end-May and June with eight very large crude carriers (VLCCs), one Suezmax and one Aframax booked so far in the past week, according to shipping fixtures.
These bookings total about 18 million barrels, which matched the Urals volume shipped in late March and April when prices of the Russian blend fell sharply amid reduced European demand after refineries closed and slashed runs as the coronavirus disease 2019 (COVID-19) choked the continent.
“The North Sea barrels that’s been floating for a while will start to clear, some of them will end up in STS (ship-to-ship) operations with the VLCCs that were booked,” said one trading source, adding that resumption of refinery runs in some European countries such as Germany will also aid in the absorption of the regional supply overhang.
According to the shipping fixtures three VLCCs will load from the STS transfer area of Skaw off the northern tip of Denmark, where traders typically load crude oil from nearby ports, including the Baltic and Norway, via smaller Aframax tankers. The sole Suezmax with load from Scapa Flow, another STS spot in the Scottish Orkney Islands in the North Sea.
This time some of the smaller tankers to offload onto the bigger vessels will include the many Aframaxes that are sitting off the UK laden with unsold Forties and other North Sea crude, including at least seven that are anchored off Dunbar close to the Hound Point loading terminal, IHS Markit MINT shipping tracking data show.
The fixtures show that all the tankers are bound for China except one VLCC that’s headed to South Korea and another that has East Asia as its destination. Aside from the North Sea, China has also recently bought large volumes of spot barrels from West Africa and Brazil, the sources said.
“As long as the economics still work and China still has enough storage space, the buying spree might continue for some time before it wanes,” said Feng Xiaonan, IHS Markit downstream analyst in Beijing, pointing to the similarly large purchase made in April that totaled almost 10 VLCCs.
Chinese crude oil imports in May and June are likely to stay at the lofty levels chalked up in April as cargoes purchased in March/April, when prices were low, make their way to the mainland, Feng said earlier.
This new round of purchases will land in China from July onwards but several incremental cargoes were already loaded in the past week, including from Norwegian ports, and are now making their way East, MINT data showed.
There are still another 151 million barrels of seaborne April-loading crude oil that are on the way to China in addition to the 221 million barrels that have already been delivered, data from IHS Markit’s Commodities At Sea (CAS) showed.
A total of 287 million barrels have so far been loaded in May bound for China, which would be the most picked up in a month in the past year except the possibly record 372 million barrels lifted in April, the data showed.
Chinese crude oil imports totaled 40.431 million mt, or about 9.9 million b/d, in April, down 7.5% from a year ago and 1.6% less than March, according to updated customs data.
The data also showed that Russia had usurped Saudi Arabia as the largest supplier last month, which went some way towards explaining the kingdom’s decision to open its taps and slash prices in April, trading sources said.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com; Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Japanese refinery runs fell further last week to the lowest in more than six years even as the government lifted a state of emergency nationwide giving hope to a rebound in oil product demand.
The utilization rate of crude distillation units (CDUs) in the week to May 23 fell to 72% of a significantly reduced total operable capacity, the lowest on OPIS records of the Petroleum Association of Japan (PAJ) data going back to January 2014. Operable capacity was down 238,185 b/d to 2.78 million b/d.
Crude throughput slumped 8.7% on-week to 13.826 million bbls, or 1.98 million b/d, according to the PAJ data, which is also the smallest on the records.
Against the country's nameplate 3.52 million b/d, runs fell to 56.1% from 61.5% the previous week.
Oil demand may find some relief, traders said, as Japan on Monday lifted the state of emergency over the coronavirus disease 2019 (COVID-19) in all prefectures including Tokyo, according to the Prime Minister's Office website.
But a Singapore-based trader doubted on how much Japanese refiners will raise runs, given high inventories of petroleum products.
"Demand will increase given the lift, but it will take time to cut inventories," said the trader.
Product stockpile in the latest week totaled 63.528 million bbls, not far from a three-month high of 64.408 million bbls reported for the week ended May 9.
Idemitsu Kosan expects jet fuel and gasoline sales in the 2020/21 fiscal year to drop 50% and 12%, respectively, amid travel restrictions and declining economic activity caused by the COVID-19, as previously reported.
With the sluggish outlook, Japanese refiners were informed of "larger-than-expected-cuts" to their June-loading term crude supply from OPEC members, the PAJ president was quoted as saying by local media.
Tsutomu Sugimori, who is also JXTG Holdings' president, said the reductions were likely to be enough to meet the lower local refining demand, although he did not reveal the extent of the supply cut, according to the reports.
Refiners may consider the possibility of seeking spot barrels in case of supply shortage should consumption recover in coming months, he said.
Officials from the PAJ or JXTG were not available for comment.
In the latest week, the country's crude inventories fell to 85.146 million bbls, the lowest since the week to May 2, according to the PAJ data.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Indian refiners are restarting a slew of crude units that were taken down in the past two months to coincide with demand-sapping coronavirus disease 2019 (COVID-19) lockdown measures that are being wound down leading to a rebound in local fuel consumption, according to market sources and local media.
The optimism associated with expectations for a sharp demand recovery, as seen in China, has led refiners to also announce plans to crank up crude throughput, which has translated into fresh spot crude oil buy tenders after their term barrels were reduced in line with the OPEC+ output cuts, trading sources said.
Indian Oil Corp (IOC), the country's largest refiner with processing capacity of 1.4 million b/d, said it would raise runs to 80% of capacity in May after slashing them down to a low of 45% in the first week of April.
IOC brought back online crude units at refineries in Panipat, 150,000 b/d after a near two-month maintenance and refurbishment program earlier this month, in Paradip, 160,000 b/d after about 10 days works in late April, and in Paradip, 120,000 b/d following an almost month-long turnaround that finished this week, according to the reports and a trading source.
Aside from IOC, other Indian refiners have also brought back units recently that were shut in part to upgrade processes to allow for the production of cleaner 10 ppm sulfur gasoline and diesel, which conform to new government standards that came into force from April 1.
Nayara Energy restarted a 110,000 b/d unit at Vadinar in late April after a over two-week closure, Bharat Petroleum Corp. Ltd resumed operations at its 100,000 b/d crude unit in Kochi this week following a three-week shutdown, while Mangalore Refinery & Petrochemicals Ltd also did the same after works at a 144,000 b/d unit for about a month, the report showed.
The moves come as the Indian Oil Minister said earlier this month that he expected domestic oil demand to increase to about 80% of pre-COVID-19 levels as the nation pulled back many of the lockdown levers to breathe live into its industrial and agricultural sectors.
India this week also announced that it would allow the resumption of domestic air travel from May 25 after a two-month gap that just about crushed jet fuel demand.
To meet the higher crude throughput refiners are increasingly tapping the spot market as their term allotments were crimped by compliance to the OPEC+ output cuts.
Trading sources said that Indian refiners such as the two-biggest, Reliance Industries and IOC, were picking up incremental barrels from West Africa as well as from the U.S via tenders.
IOC has already issued 2-3 buy tenders this month, they said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com; John Koh, John.Koh@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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The forward curve of West Texas Intermediate crude futures has significantly flattened on widespread production shut-ins and recovering demand, but the unpredictable path of the coronavirus disease 2019 (COVID-19) pandemic and possible restarts at higher prices baffle analysts as to what the future WTI curve will look like.
The "supercontango" seen just a few weeks ago that signals distress for near-dated WTI crude and scarce storage is now gone, as the front-month contract has surged relative to long-dated prices. Solid draws at key U.S. crude storage at Cushing, Okla., and other major hubs worldwide also alleviated fears of a global oil tank tops.
The front-month WTI prices settled at $33.49/bbl Wednesday, almost tripled from the $12.34/bbl on April 28. During that time, the front-to-12-month WTI crude futures spreads have dramatically narrowed to around minus $3/bbl on Wednesday, down from the nearly minus $19/bbl on April 28.
Prices of long-dated oil futures are a function of the oil market's spare production capacity, Bank of America energy analysts said. The more the spare originally said spare capacity, primarily due to voluntary production curbs, the lower the long-dated price, according to the U.S. bank.
"With OPEC+ and other producers around the world aggressively curbing supply, we now face the highest levels of spare crude oil production capacity in at least two decades," BofA said in a recent note.
The furious pace of narrowing crude spreads prompted some to think the WTI market will flip to backwardation. According to BofA, backwardation has typically occurred as prices hit $55-60/bbl in the past five years. "With spare capacity so high, we now believe that backwardation could occur at $40-45/bbl," the bank said.
The WTI futures market had been mostly backwardated between October 2017 and March 2020. Backwardation describes a market where prompt prices are higher than future deliveries, usually a sign of more robust near-term demand.
Another U.S. bank Goldman Sachs said it expects tightening of crude oil inventory to further flatten the Brent forward curve without a rise in long-dated prices. For example, the current contango in the first six months of the Brent forward curve that offers positive storage play is expected to disappear soon, pointing to further curve flattening, Goldman says.
Goldman said that deep production cuts by OPEC+ and in North America combined with demand recovery will set the stage for a large oil deficit in 2021 that will lead prices well above the forward curve, taking the oil market to backwardation.
Indeed, the U.S. Federal Reserve in late April warned of "especially difficult" conditions in the energy sector, citing plunging oil prices, a sharp global petroleum demand drop and excess supply overwhelming storage capacity.
"Some participants expressed concern that low energy prices, if they were to persist, had the potential to create a wave of bankruptcies in the energy sector," the U.S. central bank said in the minutes of its April 28-29 policy meeting released on Wednesday.
IHS Markit, a provider of critical information, analytics and solutions, said Thursday U.S. producers are in the process of curtailing about 1.75 million b/d of existing production by early June due to operating cash losses, lack of demand and storage capacity. That's nearly 10% of the 2019 total output of 12.2 million b/d.
IHS Markit is the parent company of OPIS.
Market watchers have mixed views on what the WTI forward curve will look like.
They warned that any meaningful short-term rally would lead to reduced shut-ins and production recovery. In addition, the possibility of a second COVID-19 outbreak and extremely high oil inventory levels suggest any oil recovery will likely be bumpy.
Patricia Hemsworth, senior vice president of Paragon Global Markets, a New York-based introducing broker, said that currently the December 2020 WTI contract has the highest open interest for all delivery months, even higher than the front months of July and August, suggesting some participants are expecting market conditions to improve by the end of the year.
Hemsworth said a bull market for crude can be validated when the price, open interest and volume of WTI futures are all trending higher, confirming participation by new buyers instead of shorts liquidation.
John Auers, executive vice president of Dallas-based energy consultant Turner, Mason & Co., said oil market participants should be better prepared to withstand future headwinds after the shock of WTI's historic negative $37.63/bbl settlement on April 20.
"Demand growth is going to be relative consistent till the end of the year. As a result of that, maybe we don't go back to the contango," Auers said. "There will be lots of bumps on the road. There is no certainty in the future."
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Frank Tang, ftang@opisnet.com,
--Editing by Denton Cinquegrana, dcinquegrana@opisnet.com
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Chinese fuel demand recovery is likely to taper off in the second half of this year after a spectacular V-shaped rebound from the coronavirus disease 2019 (COVID-19), which is also taking shape in countries that have relaxed lockdown measures, according to an IHS Markit report and trading sources.
Overall oil consumption in China is forecast to contract by more than 1 million b/d in 2020 from a year ago due mainly to the drag in transport fuels while demand for petrochemical feedstocks, including naphtha and liquefied petroleum gas (LPG), are expected to post modest growth, the IHS report showed.
“When you look at oil demand over February, March and April, there was a very definite V-shape recovery, except for jet fuel. Looking into the second-half, we believe the right leg of the V will be lower than the left,” said Feng Xiaonan, IHS Markit downstream analyst in Beijing, one of the authors of the report published on May 20.
Oil demand in China has recovered to more than 90% of year ago levels by the end of April but the outlook for the rest of the year is clouded by uncertainties including rising geopolitical tensions and the course the COVID-19 pandemic will take, which ultimately depends on test, treatment and vaccine developments.
The spike in demand growth was matched by an equally impressive rebound in refinery run rates with independents raising output sharply took take advantage of local fuel floor prices that raised margins significantly, according to the report.
Refinery runs in China are expected to increase to 69.8% of capacity in May, according to preliminary estimates from IHS Markit compared with typical rates of around 77% prior to COVID-19. Operations dropped to 55% in February before recovering to 60% and 68.8% in March and April, respectively, IHS Markit data show.
However, growth in the second half is unlikely to be as spectacular, Feng said.
A slowdown in fuel exports is on the cards as many countries in the region and further away are still struggling to get back on their feet in the aftermath of COVID-19, which could impact local demand and in turn Chinese shipments overseas, she added.
Nations are unwinding strict lockdown measures to varying degrees depending on local conditions with some more cautious that others in this knife-edge balancing act of getting the economy and society back to normal versus fears of a swift second wave of infections.
Fuel demand is already picking up in major consumers such as the United States, India and Germany which have loosened social distancing rules while others including Indonesia, Malaysia and Singapore still have strict measures, market sources said.
“The immediate recovery has been spectacular in China and it seems like it would be the same in the U.S.,” one trading source said.
Chinese crude oil imports in May and even June are likely to stay at the lofty levels chalked up in April as cargoes purchased in March/April, when prices were low, make their way to the mainland, Feng said.
There are another 199 million barrels of seaborne April-loading crude oil that are still on the way to China in addition to the 172 million barrels that has already been delivered, data from IHS Markit’s Commodities At Sea (CAS) showed. A total of 214 million barrels have so far been loaded in May bound for China, the data showed.
China crude oil imports totaled 43.73 million barrels, or about 320 million barrels, in April, according to customs data.
“Imports will shore up in the second quarter ahead of a full recovery of downstream demand. We also expect the pace of stock build to ease in second half 2020 as tanks get filled up and as storage economics become less attractive with crude oil prices expected to trend higher in our base case scenario,” IHS Markit said in the report.
“As such, the curve of crude imports is likely to diverge from that of downstream demand,” it said.
The Chinese government are asking refiners to import as much as they can and as much as 30% of imports that arrived in the first four months of this year may have gone into storage, Feng said earlier, stressing that China’s oil storage capacity was underestimated by industry watchers.
Turning to each transportation fuel, in its best-case scenario gasoline demand was forecast to drop by 454,000 b/d, diesel by 228,000 b/d and jet fuel by 360,000 b/d, according to the report.
“In percentage point terms, jet fuel demand is the hardest-hit by the COVID-19 crisis,” it said, adding, “We do not expect the lifting of travel restrictions to instantly bring all demand back, as it will take time for passengers to switch back to using public transport owing to safety concerns.”
On the other hand, China’s naphtha demand is expected grow by 70,000 b/d and LPG by 20,000 b/d in 2020, the report showed.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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The worst of the ethanol industry demand destruction caused by the coronavirus diseases 2019 (COVID-19) outbreak may be over, speakers at a University of Illinois webinar said Tuesday, echoing statements made days earlier by a leading industry trade group.
The peak of demand destruction created by the coronavirus disease 2019 (COVID-19) pandemic could be in the ethanol industry's rearview mirror, said a University of Illinois clinical assistant professor and agricultural economist, Todd Hubbs.
"When we think about where ethanol is headed, I think we may have seen the worst of it, barring some kind of rekindling of the pandemic," Hubbs said. "I think we're in a build-and-strengthen mode."
Hubbs pointed out that ethanol production has increased in recent weeks, citing recent data from the U.S. Energy Information Administration (EIA). "We saw ethanol plants shutter and reduce production, and we got down to 537,000 b/d a few weeks ago. It picked up to 617,000 b/d in last week's report. I expect it to go up again this week."
The agency on Wednesday reported that ethanol output rose by 46,000 b/d, or 7.5%, in the week ended Friday to 663,000 b/d, a six-week high. Production, however, is 38.1% below the same week of last year.
The damage that COVID-19 has caused the ethanol industry came after a particularly rough year for producers, Scott Irwin, an Illinois agricultural economist, added. Irwin said producers' average profits in 2019 were at their worst since 2012.
He said the "shutdown price" for a representative Iowa ethanol plant was around 80cts/gal. Prices briefly dipped below that in March, and nearly half of ethanol production in the U.S. was idled at some point, Irwin said.
Eric Mosbey, general manager at Illinois ethanol producer LincolnLand Agri-Energy, said his 60 million-gal/year plant has been operating at reduced rates since fuel demand plunged in March on COVID-19 lockdown restrictions across the U.S.
"We slowed -- that's how we coped with things," Mosbey said. "We slowed to try to match our production to demand, and cut costs as much as we possibly can and then see how that plays out. Now, we're starting to feel a little more stable as we start to see demand come back."
He said May will likely mark the company's production low and that he hopes demand will continue to rise through the summer. "It's going to be really interesting to watch how the ethanol industry responds throughout this recovery," he added. "Will we come right back on and blow right through those old production numbers and increase stocks again, only to crash the margin? Or will we take a more measured approach and more disciplined approach? I'm hoping for the latter."
Irwin said he believes Congress will eventually pass legislation that will provide financial assistance to the biofuels industry, but said it may not be as generous as what House Democrats proposed in a roughly $3 trillion COVID-19 economic stimulus bill that passed the chamber in a mostly party-line vote on Friday. Language in that bill would pay biofuel makers 45cts/gal for fuel they produced over the first four months of 2020. The provision has little support in the Senate, and on Wednesday Sens. Chuck Grassley, R-Iowa, and Amy Klobuchar, D-Minn., introduced a bill that would direct USDA to reimburse biofuel producers for 75% of their first-quarter feedstock costs.
The panelists' comments come after Geoff Cooper, president and CEO of the Renewable Fuels Association (RFA), an ethanol industry trade group, told reporters on Friday that "the worst may be behind us. We're beginning to see some signs of recovery as states begin to ease stay-at-home restrictions and people begin to return to public spaces and get back out on the roads."
As demand for gasoline has risen, Cooper said more ethanol plants are starting to come back online. "So it does seem that we're starting to see a light at the end of the tunnel, but make no mistake, we still have a very long way to go to climb out of the hole that COVID-19 put us in and by our last count there are still more than 60 ethanol plants that are idle today and close to 75 or 80 facilities that are still operating at greatly reduced output rates."
Speakers on the webinar also expressed concern over whether a potential second wave of COVID-19 infections in the fall could lead to a second plunge in fuel demand.
"I know there's been a lot of negativity about a resurgence of the coronavirus and what that will do to the economy," Hubbs said. "That uncertainty is huge, and it will have big implications to gas demand, ethanol production, and on top of that, corn use for ethanol."
Looking even further into the future, the panelists compared the COVID-19 demand dip to losses the industry could suffer if electric vehicles (EVs) are widely adopted.
Irwin said it depends on the duration of the transition to EVs. "It might be faster than conventional wisdom might lead you to believe," he said.
"We see a lot of car companies investing in this technology," said Hubbs. "The money's been put in, and I think the cards have been dealt. It's not going to be an immediate shock like we saw with COVID-19 -- I think it's more of a gradual grind downward that lasts multiple decades."
But Mosbey said he sees an opportunity for ethanol, perhaps in the form of ethanol-electric hybrid vehicles.
"That's a nice path forward for an ethanol plant or for agriculture," Mosbey said. "Growth for the ethanol industry is not impossible, but I would say it looks like it will be challenging if we don't have significant exports pick up.
And we don't see a way to get ethanol into other countries and start to put it in their gasoline supplies, because it does seem like the writing might be on the wall for electric cars.
"It's going to take time. It goes back to production discipline, how we manage these plants going forward, and what options can we come up with to make them profitable with other products and product diversification and continuing to utilize the U.S. corn crop."
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--Reporting by Aaron Alford, aalford@opisnet.com;
--editing by Jeff Barber, jbarber@opisnet.com
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Retail prices for diesel and gasoline in Germany, the United Kingdom, France, Spain and Italy plunged in April amid regional travel restrictions to curb the spread of the coronavirus disease 2019 (COVID-19) pandemic, according to data from OPISNAVX.
Diesel prices plummeted the most of the five countries in Spain, due to the country's stringent movement restrictions, as values fell by 9.37 euro cents/litre (12.5 dollar cents/litre) in April compared to March. Spanish motorists paid the least for their diesel of the five countries, at 1.03 euros/litre. In comparison, Italian motorists paid the most, at 1.34 euros/litre for diesel at the pump, OPISNAVX data show.
Diesel prices in April across all five economies declined by an average 6.3% compared to March, while gasoline prices fell further still.
Gasoline prices declined the most in Germany, shedding 11 euro cents/litre in April compared to March and nearly 30 cents/litre compared to April 2019.
Spanish gasoline prices were the cheapest among the five countries, at 1.11 euros/litre, while Italian drivers paid the highest pump price for gasoline, at 1.46 euros/litre.
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--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Vietnamese gasoil importers returned to the market after a five month hiatus as the nation scaled back stringent coronavirus disease 2019 (COVID-19) lockdown measures, among the first to be implemented in the world, as the rate of infections flatten.
The opening up of the industrial, agricultural and entertainment sectors as well as removal of travel restrictions has bolstered diesel demand, traders said.
Three of the nation's importers floated at least six tenders seeking as much as 165,000 mt of 500 ppm sulfur gasoil for delivery in late-May to early-July. The last buy tender was issued by Petrolimex in December 2019, according to OPIS records.
This time, Petrolimex is seeking via a tender 35,000 mt for May 27-31 loading from either Singapore, Thailand, Malaysia, or South Korea.
It had also earlier issued another tender for 70,000 mt for May 21-June 15 loading from the same locations.
On its part, PetroVietnam is seeking up to 30,000 mt for June 15-23 delivery, according to a tender which closed on May 19.
It has previously sought 20,000 mt for May 20-June 5 delivery.
Saigon Petro has a tender for up to 10,000 mt for either July 1-5 delivery, or June 24-July 2 loading from either Singapore, Thailand, Malaysia, or South Korea, according to a document.
Apart from seeking incremental gasoil imports, refiners are also channeling their output to the domestic market to meet recovering demand, market sources said.
Nghi Son Refinery and Petrochemical (NSRP), for example, will not export any spot diesel cargoes in May and June, according to sources with knowledge of the matter.
NSRP typically exports via term deals but will turn to the spot market when buyers cancel their liftings. It last issued a sell tender for 32,000 mt loading on April 10-12, which was canceled due to a lack of interest, traders said at that time.
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--Reporting by John Koh, John.Koh@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Pay for fuel with your license plate.
That's one of the frictionless payment initiatives Alimentation Couche-Tard Inc. has rolled out in response to the coronavirus disease 2019 (COVID-19) crisis. And there are more ways the convenience store giant is adapting to the "new normal" in the wake of the virus, according to a status report released today.
Like other convenience-fuel retailers, Couche-Tard has pulled forward certain technologies that could help with social distancing during the pandemic as well as serve customers in the future. The company is also tweaking its inventory based on changing consumer purchasing habits. And it has adopted new policies to protect customers and employees.
As OPIS has reported, convenience store operators are expanding delivery service and online ordering for pick up, as well as adopting technology such as scan-and-go to reduce the need for social interaction and to speed transactions.
And in its report, Couche-Tard said it also has "pulled forward" technologies that could become "key to serving customers beyond the current pandemic." Among the initiatives are: adopting a "frictionless" payment technology in Norway to accept fuel payments using license plate recognition; expanding home delivery in North America to more than 620 stores; and offering click-and-collect and curbside delivery in Europe and North America with preordering and payment through the Circle K app.
Couche-Tard said that in Europe shopping behavior began to change during the second week of March when the World Health Organization had officially declared
COVID-19 a pandemic. "In North America, the impact on shopping trends was similar but lagged that of Europe by one week," the company said, noting that its stores remained open during stay-at-home orders throughout most of its footprint because fuel retailers and c-stores were considered essential businesses.
"Fuel volumes declined rapidly during the first few weeks that followed the implementation of restrictive measures across the different regions but stabilized during April and began to see a gradual improvement in the latter part of the month. Fuel margins overall have benefited from the rapid and steep declines in crude pricing," the company said.
In the early days of the crisis, in-store sales benefited from "pantry stocking," but merchandise sales declined starting in mid-March due to lower traffic. "Overall, a higher average basket helped offset a portion of the lost customer visits," the company said.
Couche-Tard and other convenience store chains have reported higher demand for alcohol and tobacco products, as well as basic staples, canned and dry goods and cleaning and sanitation products. The company said the demand for those products has helped offset lower demand in the prepared food category.
"Couche-Tard's teams in Europe recommended adjustments to the in-store assortment, which allowed stores in North America to better anticipate the changes in shopping behavior and the items that could see greater demand," the report said.
Regardless of the decline in prepared food business, Couche-Tard said in its report that it still plans to have its "Food at Scale" food service initiative in 1,500 locations by this fall. "This continues to be an important area of focus and capital expenditures for this initiative remain in the budget for fiscal 2021," the company said.
As essential businesses, c-stores have adopted measures to protect employees from exposure to the pandemic and to reward them for their efforts to keep stores cleaned and well-stocked during the crisis. Couche-Tard's Emergency Appreciation Pay Premium of $2.50/hour in North America for hourly workers in stores and distribution centers is in line with the $1/hour-$3/hour other c-stores have said they are paying. For North American workers, the company also set up an Employee Assistance Plan during the pandemic and an Emergency Sick Care Plan for hourly workers that includes a bank of sick pay and a pay continuation benefit for employees diagnosed with the virus or placed under mandatory quarantine. The company also provides access to virtual healthcare for hourly employees in the United States.
Couche-Tard said it has set up a COVID-19 Assistance Fund to help employees "most severely impacted" by the pandemic. The assistance is drawn from salary contributions by Founder and Executive Chairman Alain Bouchard, President and CEO Brian Hannasch and other members of Couche-Tard's executive leadership.
The company said it is moving to "preserve its cash position and financial flexibility, including a pause to share repurchases." As previously reported, it also put its acquisition of Caltex Australia on hold. As of Feb. 2, 2020, Couche-Tard said it had $1.8 billion in cash and equivalents on its balance sheet and another $2.5 billion available on its revolving credit facility. CFO Claude Tessier said the company went into the crisis in a "strong position" and is taking steps to "be ready to reinvest in our business and in the economy when the time comes to exit this crisis."
Couche-Tard did not respond to questions on further detail concerning the impact of the virus on its company and specific initiatives by presstime Tuesday afternoon.
Take action with real-world news and tips geared for fuel marketers, convenience store operators and gas station managers with OPIS Oil Express Newsletter.
--Reporting by Donna Harris, dharris@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Crude oil fundamentals have improved significantly in the past week as the OPEC+ output cuts continue to crimp supplies pushing buyers, especially China, to pick up incremental barrels from the spot market, sending differentials soaring high into the positives, trading sources said.
Tighter supplies that was reflected in numerous May loading programs and term allocations were repeated in June but to a greater extent for clients of Saudi Aramco after the kingdom unilaterally reduced output for next month by an additional 1 million b/d, they said.
“The June allocations from Middle East producers were confirmed to Asian customers. Saudi Arabia has cut a lot, even refiners in China and India received cuts. That’s why there’s a lot more demand for spot cargoes,” said one trading source.
“China will mop up all the cheap spot barrels that are out there,” the source said, adding that this general rebound in market fundamentals as seen through the narrowing contango and bigger premiums, could encourage traders to release their stored barrels, especially those kept on board tankers.
Spot June-loading Basrah Heavy crude to Asia, for example, traded at a premium of as much as $5/bbl to its official selling price (OSP) compared with an average of around $3.50/bbl for May barrels. Similar increases were also seen in other actively spot traded key grades such as Urals, Murban and Upper Zakum, the source said.
The front-month July-August Globex Brent contango narrowed to $0.18/bbl at the Singapore 4:30 pm close on Tuesday compared with a whopping minus $3.68/bbl for the June-July spread a month ago on April 17.
Trading sources said China is likely to emerged as a big spot buyer if the economics work in bringing long-haul cargoes to their shores as local refiners hike runs on the back of renewed industrial activities and transport fuel demand as coronavirus disease 2019 (COVID-19) restrictions are relaxed.
However, this has to be balanced against the bumper crude oil volumes that are already on their way to China after buyers took huge advantage of the deep price falls to purchase a lot of April loading cargoes, they said.
There are another 215 million barrels of seaborne April-loading crude oil that is still on the way to China in addition to the 155 million barrels that has already been delivered, data from IHS Markit’s Commodities At Sea (CAS) showed.
The total volume of about 370 million barrels that was loaded in that one month, a massive 62% jump from March, was the most in CAS records going back at least four years.
So far in May, 185 million barrels, or about 10.3 million b/d, have already been loaded, the CAS data showed. Of the total 230 million barrels shipped out in March, about 30 million have yet to reach China, according to the CAS data.
China placed a lot of its crude arrivals in March and April into storage as domestic refinery runs were hurt by the demand erosion caused by COVID-19. But now, it is one of the first countries to emerge from this pandemic and is chalking up impressive domestic fuel demand recovery, apart from jet fuel.
Crude throughput in April jumped to 53.85 million mt or about 13.1 million b/d, data from the National Bureau of Statistics (NBS) showed. This volume processed is 0.8% more than March, according to the NBS data show. However, NBS gets its data from refiners which at times are under or over reported and often leads to revisions, sources said.
The NBS data also showed that runs in March were 6.6% less than February.
The run rate of 13.1 million b/d would work out to about 77% of Chinese refining capacity, or around 3.5% more than a year ago, which IHS Markit analysts say is well above than their estimates of 11.7 million b/d.
The IHS Markit estimate is more line with what’s happening on the ground where national oil companies have run their refineries at lower rates while independents have cranked up to as high as 77% of their capacity as they took advantage of the domestic fuel floor price mechanism.
“Downstream oil demand is only 90% of last year's level, considering the refiners' high stocks built throughout the first quarter it's hard to imagine overall runs can flip to positive growth,” said Feng Xiaonan, IHS Markit downstream analyst in Beijing.
Refinery runs in China are expected to increase to 69.8% of capacity in May, according to preliminary estimates from IHS Markit compared with typical rates of around 77% prior to COVID-19. Operations dropped to 55% in February before recovering to 60% and 68.8% in March and April, respectively, IHS Markit data show.
“The Chinese government are asking refiners to import as much as they can. China may have much more crude in storage than people expected, it could be as much as 30% of imports going into storage,” Feng said earlier, referring to arrivals in the first four months of the year.
Oil traders said that there will be no shortage of sellers looking to place cargoes that are currently floating around the world with Chinese buyers renewing their interest in cargoes from the U.S. after snapping up supplies from Brazil and West Africa.
CAS data show that there are about 176 million barrels of crude oil stored on board 133 tankers made up of 65 very large crude carriers (VLCCs) and 68 Suezmax.
“We are seeing some traders holding North Sea crude on floaters starting to show them to Asian refiners,” said one source, adding that it was likely that in the coming days some of these would begin their journey East.
Shipping fixtures this week show Unipec booking three VLCCs, the New Pioneer to load from the North Sea on June 5-10, the Amyntas from Skaw, a ship-to-ship (STS) transfer site, on May 25-30 to Ningbo at a cost of $6 million and the Nave Galactic also from Skaw on June 1-5 to the same port at the same price.
Mercuria booked the VLCC DHT Panther to pick up a cargo from the USG to South Korea on May 25-30 at a cost of $5.95 million, the fixture showed.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Personal travel in the United States is now about 25% off where it was before the start of the coronavirus disease 2019 (COVID-19) outbreak. But even as motorists return to the roads, AAA is forecasting Memorial Day travel will likely hit record lows.
In its latest summary of U.S. travel data on Monday, research firm Inrix said personal travel in the United States during the week ending May 15 increased for the fourth-straight week in a row and is now at levels last seen on March 21. That was shortly after states began instituting stay-at-home orders aimed at slowing the spread of COVID-19. The national rate of travel has now increased every day since April 15, with last week 25% off normal levels compared to 29% off normal a week earlier.
Personal travel rebounded across all states, with four states seeing travel off by less than 10% from the pre-COVID-19 baseline level. Travel in Wyoming remains the least-affected by the COVID-19 outbreak, with levels only 1% off those seen before the start of efforts to contain the pandemic. Two states, Hawaii (51%) and New Jersey (43%) continue to see travel off by more than 40% from the baseline, while 12 states saw the level of travel off by between 30% and 39%. Travel was off between 20% and 29% in 18 states and it was off between 10% and 19% in 14 states.
Meanwhile travel also increased in 97 of 98 metropolitan regions tracked by Inrix, with only Albany, N.Y., seeing travel decline -- sinking 0.5% lower than a week earlier. New York City continues to see travel lag furthest behind baseline levels, at 46% off pre-COVID-19 levels, followed closely by San Francisco, 45%, Miami, 45%, and Orlando, 43%. Inrix said Mobile, Ala., was the first metropolitan area to see travel "recover" from the COVID-19 outbreak, with travel 1% higher than pre-COVID-19 baseline levels.
National longhaul truck travel also increased again during the week, now 6.1% off pre-pandemic levels, compared to 7.6% the week earlier.
The increases in travel came as many states around the nation began lifting stay-at-home orders and opening some businesses last week. But even as life in the United States slowly begins to head back toward normal, AAA is saying anecdotal reports suggest fewer people will be traveling for the Memorial Day weekend this week than in past years.
"Last year, 43 million Americans traveled for Memorial Day Weekend -- the second-highest travel volume on record since AAA began tracking holiday travel volumes in 2000," said Paula Twidale, senior vice president, AAA Travel. "With social distancing guidelines still in practice, this holiday weekend's travel volume is likely to set a record low."
Memorial Day is considered the unofficial start of the summer season, and driving activity is thought to provide an early glimpse into gasoline demand during the summer driving season.
Memorial Day 2009 holds the record for the lowest travel volume at nearly 31 million travelers, according to AAA. That holiday weekend came toward the end of the last great recession.
Travelers who do take to the road will likely find gas prices substantially lower than last year. The national average price of regular unleaded is $1.8791 today, according to AAA data, nearly $1/gal less than the $2.8544/gal seen at the same time in 2019. National gas prices, however, have been increasing since reaching a recent low of $1.7682/gal on April 29.
AAA said that because COVID-19 has made economic data unreliable this year, it will not issue a formal Memorial Day travel forecast of the number of people it expects to be on the road -- the first time in 20 years that it hasn't issued such a report.
The agency said that since April it has started to see a modest increase in online travel bookings, suggesting that people's confidence is slowly improving. The agency said it expects that this summer, most travel will involve road trips to local and regional destinations.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Steve Cronin, scronin@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Deploying technology to scrub ship exhaust emissions remains more economically viable than burning fuel oil with a lower sulfur content, chief shipping analyst at Baltic and International Maritime Council (BIMCO) Peter Sand told OPIS on Monday.
Many shipowners expected a fast payback from their investment in scrubbers, indicated by forward swaps curve values for high- and low-sulfur fuel oils after the implementation of new International Maritime Organization legislation on Jan. 2 this year, which mandated the use of very-low-sulfur fuel oil unless an exhaust gas scrubbing system was onboard.
The spread between HSFO and VLSFO barge spot prices loading in Rotterdam was $313.25/metric ton on Jan. 2, shrinking to just $58.75/ton by May 15, according to OPIS marine fuel pricing data. The spread between the two fuels contracted as oil prices plummeted amid the global reduction in oil demand due to travel-restriction efforts to contain the coronavirus disease 2019 (COVD-19) pandemic.
"Cancelling scrubber installations on the basis of the current low spread -- No, I don't think that will happen," Sand told OPIS. "Cancellation or postponement due to financial distress may be seen in some cases, as loss-making freight rates are all around in dry bulk and container shipping sectors. Payback times are extended at the moment, but owners know their spreadsheets and operations. It still makes economic sense."
Sand expects the spread between VLSFO and HSFO to widen to a more typical level of around $150-200/ton once the oil market becomes less volatile and the usual ratios between refined products start to emerge. Demand to retrofit scrubbers that can cost between $1.5 million and $5 million to install, according to IHS Markit analysts and industry sources, has slowed due shipyards suspending operations amid the COVID-19 pandemic.
"Payback times are highly dependent on price spreads but also on vessel size, route, fuel economy and of course the price paid for the scrubber system and its installation," said Hedi Grati, refining and marketing consulting director at IHS Markit, the parent company of OPIS.
Around 2,000 ships had scrubbers installed at the start of the year and this is forecast to around 3,400 ships by the end of the year, according to IHS Markit analysts.
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--Reporting by Stacy Irish, stacy.irish@ihsmarkit.com;
--Editing by Rob Sheridan,rob.sheridan@ihsmarkit.com
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Analysts at Citi observe that the worst of the virus-inspired demand shock is over, enabling its research team and others to focus more intently on supply.
In a 36-page report for clients issued Tuesday, they see twists and turns for Brent and WTI but conclude with much higher price forecasts than current forward curves imply.
The bank now believes that the global demand decline in the second quarter will be around 15.7-million b/d, well below some of the more aggressive targets as well as the consensus view. The focus now turns to how much of the shelved or shut-in oil comes back, and into what markets and how soon?
The investment house is generally confident that OPEC+ has addressed the glut, portending more reasonable balances down the road. News of Gulf Cooperation Council countries slashing an additional 1.18-million b/d of crude helps and it now appears that OPEC+ countries are considering longer extension terms for the more than 9-million b/d of production already cut.
OPEC+ members will meet again in the first week of June. Citi OPEC+ anticipates that meeting will take place against the backdrop of strong compliance, with the notable exception of Iraq. That country's production is estimated at 4.4-million b/d in the first third of May, or some 800,000 b/d above pledged quota.
Citi believes that if Brent is priced between $30-$35/bbl at the time of the conclave, they may keep the OPEC+ cuts in place through at least July and even September. August Brent, which will represent the prompt contract when delegates gathered, closed under $30 bbl Wednesday. Uncertainty is expressed as to whether planned tranches of production increases will follow the schedule outlined in the April 2020 agreement.
The greatest uncertainty, however, is attached to the U.S., which Citi describes as the "largest and only true swing producer." U.S. crude production clearly peaked at 13.1-million b/d in March, and the bank sees a September trough of around 9.6-million b/d, resulting in a total decline of 3.5-million b/d.
Most interestingly, the bank suggests that shale production isn't dead but in a temporary limbo. Oil rig counts could stay low through 2020 and companies might need to see $40 bbl or higher WTI numbers before drilling more wells. But Citi does believe that WTI could bounce back to $42 bbl in the fourth quarter of this year.
The return of U.S. production is entirely tied to price. Majors might only need two months with WTI above $35/bbl to act, while independents might require 3 months above $40/bbl. The bank's commodities' team has faith that markets will get to those levels. Official projections are for a WTI average of $33/bbl in 3Q2020 and a $42/bbl target for the fourth quarter.
The numbers in 2021 advance significantly. Citi projects an average Brent price of $56/bbl next year with WTI coming in at $52/bbl. By 2022, US oil production growth should recover toward 1-million b/d and perhaps even move global balances toward a small surplus. The bank also believes that oil price time spreads in the first half of 2021 will move back into backwardation.
There are caveats aplenty. In addition to uncertainty about future waves of COVID-19, supply risks to the upside exist for Norway, Guyana, Brazil, and even Canada. Among OPEC countries, more barrels might surface from Libya, Iran, Iraq and even Venezuela.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
- Reporting by Tom Kloza, tkloza@opisnet.com;
- Editing by Steve Cronin, scronin@opisnet.com
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While many petrochemical markets have been affected by demand that dropped rapidly amid quarantines around the world related to the coronavirus disease 2019 (COVID-19), toluene has been hit particularly hard.
Despite supply curtailments as US refinery run rates dropped to 70%, toluene supply has been building as the gasoline markets have essentially shunned the commodity chemical as blenders are swarmed with competitive offers for other blendstocks. The US produces about 8,250 mt/day of toluene; gasoline blending accounts for almost 50% of toluene demand.
Prior to the US declaring pandemic conditions, toluene was trading around 85 cts/gal above RBOB. Today, that spread is nearing 20 cts/gal. The best prices that high-quality toluene have seen recently were from certain solvent chemical markets, but demand is too shallow to have any meaningful impact.
Buying from the solvents sector briefly pushed up toluene prices by a few cents in early May, but when it evaporated, the market fell right back to gasoline blending values.
Mixed xylenes (MX) markets are also suffering from low demand from both chemical and gasoline sectors, but to a lesser extent than toluene. A brief arb to Asia alleviated some of the MX oversupply, but its price tanked 10 cts/gal when that activity ended, hitting a new low of 23 cts/gal over RBOB. Like toluene, MX was trading at more than 80 cts/gal above RBOB prior to the pandemic.
All gasoline blendstocks have been hit hard in the COVID catastrophe. On Feb 3, CBOB was about 145 cts/gal in the USGC and its spread to premium was 14.75 cts/gal. On Wednesday, CBOB was about 73.5 cts/gal and the spread to premium was actually higher at 17 cts/gal.
Along with the outright price for regular grade, differentials for other high octane blendstocks have fallen. In early February, alkylate (92 octane 5.5 RVP) was 39 cts/gal over gasoline and reformate (100 octane, 1 RVP) was 62 cts/gal over gasoline. On Wednesday, alkylate was 16 cts/gal over gasoline and reformate a 35 cts/gal over gasoline. Raffinate, a 60-65 octane blendstock has gone higher on a differential basis, moving from 20 cts/gal below gasoline in early February to 10 cts/gal under gasoline, but the slide in gasoline means that raffinate's outright price slid from 125 cts/gal to 63.5 cts/gal.
OPIS PetroChem Wire's Daily Wire provides closing prices and a summary of the day's trading activity for US ethylene, proylene, polymers and upstream NGLs markets. Begun in 2007, its olefins and polyolefins prices serve as benchmarks for a number of physical and swap contracts that trade on the CME/NYMEX Clearport system. Learn more & try it free
--Reporting by Shayan Malayerizadeh, Shayan.Malayerizadeh@ihsmarkit.com and Robert Sharp, robert@petrochemwire.com
--Edited by Diane Miller, Diane.Miller@ihsmarkit.com
Copyright, Oil Price Information Service
Sales of marine fuels in Singapore, the world's largest bunkering port, rose in April from a year ago in contrast to the demand decimation seen on other transportation fuels such as gasoline, diesel and jet fuel due to coronavirus disease 2019 (COVID-19) lock down measures across the world.
Fuel sales in April rose a surprising 11% to 4.11 million mt from 3.71 million mt a year ago but was down slightly from 4.32 million mt in March, according to preliminary data from the Maritime Port Authority of Singapore (MPA).
Shipping and bunkering sources were hard pressed to explain the demand jump, which they said may possibly be due to a slowdown in cargo flows a year ago when China and U.S. were at loggerheads in a trade war amid an increase in the overall global vessel fleet.
Singapore flagged shipping tonnage increased to 96,838,000 gross ton in April 2020 from 93,926,000 gross ton in April 2019, data from MPA showed. The April marine fuel sales volume is also well above the 3.95 million mt monthly average chalked up last year.
However, month-on-month the dip is clearly reflective of COVID-19, which has curbed global trade. The number of vessels that visited Singapore for bunkering dropped to 3,202 from 3,557 in March, MPA data showed.
The Purchasing Managers' Indexes (PMI) across Southeast Asia slumped below 50, the dividing line between expansion and contraction, with Singapore down at 44.7 in April from 45.4 in March, according to data from IHS Markit. China, the world's second-biggest economy also registered a PMI contraction of 49.4 in April from 50.1 in March.
The sales volume shows that the industry is recovering following the record January pent-up record sales of 4.51 million mt, analysts said. Demand surged on the back of new IMO regulations that implemented a 0.5% sulfur cap on vessels without scrubbers from January 1, 2020.
Sales of low sulfur fuel oil (LSFO) with a maximum sulfur content of 0.5% dipped in line with the overall sales but still remained as the large marine fuel grade sold in April, accounting for 69% of total volume. This solidified its status as the preferred bunker fuel among shippers post-IMO 2020.
LSFO sales totaled 2.85 million mt in April, down from 3 million mt in March with the 380 CST grade being the preferred choice at 2.15 million mt, the MPA data showed.
"The higher viscosity makes it easier for ship engineers to handle," said a European shipowner.
While only 597,800 mt of 100 CST LSFO and 111,100 mt of 180 CST LSFO were sold in the same month.
"Typically distillate blending falls into the 100 CST grade, since it is a maximum specification, while those that are produced from residue steams will be mostly in the 380 CST grade, thus leaving very little supply of 180 CST," said Matthew Chew, principal oil analyst at IHS Markit in Singapore.
Delivered LSFO bunker price in Singapore averaged at $239.19/mt in April, down from $317.55/mt in March, according to data from OPIS, a unit of IHS Markit.
Sales of high sulfur marine fuel oil (MFO) were slightly higher at 771,200 mt in April from 738,400 mt in March, of which 692,800 mt were 380 CST and 78,400 mt were 500 CST.
Under the IMO 2020 regulations, only vessels installed with scrubbers are allowed to burn 3.5% sulfur MFO. IHS Markit estimates that around 3,897 ships out of an approximate global fleet of 96,000 will be fitted with scrubbers by Jan 1, 2021.
MONITOR KEY BUNKER FUEL PRICES AND RELATED GLOBAL SHIPPING MARKETS.
OPIS Global Marine Fuels Report delivers daily assessments of marine bulk and bunker fuel prices in key global ports, including calculated prices for the new 0.5% VLSFO, a new fuel created in anticipation for IMO 2020. Easily track cargo and bulk fuel prices for Asia, Mideast, Europe and the Americas with this concise report filled with at-a-glance tables and charts. Start Your Free 30-Day Trial
--Reporting by Thomas Cho, Thomas.Cho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Asian ethylene plant operators plan to crack less liquefied petroleum gas (LPG) in June for a third consecutive month due to sustained strength in the gas and cracker turnarounds. However, LPG intake may rebound during the northern hemisphere summer.
LPG usage for petrochemical production in June is set to decline 2% on-month to 350,000 mt, according to an OPIS poll completed on May 11. Revised figures show that in May, gas cracking volume is to fall to 357,000 mt from 436,000 mt in April, according to the survey.
LPG prices strengthened in the past month amid a surge in demand from India and Indonesia following lockdown measures to contain the coronavirus disease 2019 (COVID-19), which boosted demand for the cooking fuel. The CFR Japan propane price on April 20 rose to as high as $356/mt, the strongest since March 6, data from OPIS, a unit of IHS Markit, showed.
Higher LPG prices deteriorated gas cracking economics with the propane/naphtha ratio assessed at 179.3% on April 15, the highest on data going back to July 2014. The ratio fell to 116.8% on May 11.
Petrochemical producers typically find it more attractive to crack naphtha instead of LPG when the ratio rises above 90%.
The trend of reduced LPG usage, however, may reverse in summer when demand for the heating fuel usually declines and as naphtha prices rebound in line with rising crude markets, said Matthew Chew, principal researcher at IHS Markit in Singapore.
"Our forecast as of end-April is showing that LPG cracking will remain unattractive till June before improving," Chew said.
"It will be more attractive from July onwards because of declining LPG demand, as well as improving crude and naphtha prices assuming that the COVID-19 outbreak is under control by then."
Naphtha values rebounded on signs of a recovery in gasoline with the CFR Japan prices up 50.5% to $249.50/mt on May 11 from $165.75/mt on April 1, the lowest on the OPIS data going back to July 2014.
The CFR Japan propane price fell 17.3% to $294.50/mt when from the April 20 peak.
"There seem to be only strong factors for LPG right now," said a buyer at a Japanese chemical producer who participated in the survey. Demand in Asia is strong, while LPG supply is likely to be tempered by the OPEC+ agreement to curb oil production, he added.
Ethylene production costs and margins from naphtha were better than LPG, according to the IHS Markit Asia Light Olefins Weekly report published on May 8.
The cash cost of steam cracking in Northeast Asia using naphtha was estimated at $116/mt as of April 30, generating a margin of $239/mt, the report showed.
The costs of cracking LPG was almost quadruple at $457/mt and the margin was minus $102/mt.
Ethylene market sentiment in Northeast Asia strengthened on tighter supply amid cracker turnarounds and bullish energy prices with some governments relaxing curbs against the COVID-19, the report said. Propylene market sentiment also firmed up, according to the report.
In Japan, Mitsubishi Chemical on May 12 shut its 539,000 mt/year cracker in Kashima for planned maintenance works, a company spokesperson said. The works will last about two months.
Maruzen Petrochemical also idled its 525,000 mt/year cracker in Ichihara on May 11 for scheduled turnaround expected to last two months, according to a company source.
Mitsui Chemical planned to conduct maintenance works at its 500,000 mt/year cracker in Osaka from June 11 to July 20, according to a company source.
Some petrochemical makers in Asia maintained lowered runs on expectations that downstream demand may weaken again with the COVID-19 hurting the global economy. The Asian Manufacturing PMI, compiled by IHS Markit, fell to 43.9 in April, the lowest since March 2009, from 48.3 in March, indicating a deterioration in regional business conditions.
The dismal economic situations caused one of the survey participants to mull slashing operating ratios further.
"We are considering further run cut, even probably to around 80%," said the buyer at a petrochemical manufacturer in Northeast Asia, adding their cracker has been operating at around 90%.
"A rate below 80% is unlikely, given naphtha inventories," he said.
Methodology: IHS Markit OPIS collects Asian petrochemical companies' plans for the current month and the next month, as well as actual cracking volume in the previous month. IHS Markit OPIS checks if any manufacturers revise their plans for the current month and if any manufacturers crack more or less than initial plans in the previous month. IHS Markit OPIS contacts feedstock procurement officers of each companies for the survey by phone, email or messengers in the last week of previous month or the first week of the current month. IHS Markit OPIS surveys 16-20 companies a month.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com, Masayuki Kitano masayuki.kitano@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
Copyright, Oil Price Information Service
Chinese refiners will sharply reduce gasoline exports in May from April as the coronavirus disease 2019 (COVID-19) hurt overseas demand while higher domestic margins kept more product at home, trade sources said.
Oil companies have chartered just two tankers to load 65,000 mt in May from China so far, down from a massive 16 vessels booked to lift 680,000 mt in April, according to shipping fixtures.
Lower exports are expected to provide further support to the broader Asian gasoline market, which started rebounding over the past few days on signs of a consumption recovery as some governments relaxed preventive measures against the pandemic, they added.
"China's May exports would be around half of April as export margins are weak while domestic margins are firm," said a Singapore-based trader, while declining to comment on exact volumes.
"The cut will be big enough to cover all bearish factors such as the possibility of sales of floating gasoline cargoes," he added.
A Singapore-based analyst said 92 RON margins in China based on domestic wholesale prices were estimated at around $11/bbl. In contrast, Singapore 92 RON crack was negative at a minus $0.582/bbl as of May 11, according to IHS Markit OPIS data.
Domestic margins in China were supported as authorities in March decided not to cut local product prices further after global crude prices fell below $40/bbl, the floor for the nation's product pricing system, as reported earlier.
Consumption also recovered as COVID-19 travel restrictions in the country were eased.
Regional demand also showed signs of rebound with other countries such as South Korea and India loosening similar curbs. The Singapore 92 RON crack on May 11 was still far better than minus $12.986/bbl reached on April 14, the lowest on IHS Markit OPIS data going back to July 2014.
"If demand is itself recovering at the same time as they cut back exports, then we may see some support on regional gasoline cracks," said Feng Xiaonan, IHS Markit downstream analyst in Beijing when asked about gasoline consumption in Asia.
"Demand depends on how we assume the COVID-19 will play out. If the conditions get better, I don't see why gasoline will stop from recovering further," Feng added.
China's refiners, however, will have to increase exports eventually as there was little room for more growth in domestic consumption and inventories will increase on higher crude runs, the Singapore-based analyst said.
They were just holding off exporting for May, hoping for a recovery in margins from June onward, the analyst added.
"Domestic demand is now already back to 90-95% of usual levels, so there is limited upside of any demand increase," the analyst said.
In the first quarter, China exported 4.55 million mt of gasoline, up 21% from a year earlier, according to IHS Markit OPIS calculations based on the customs data.
China released two batches of oil product export quotas for this year so far, allocating a total of 49.19 million mt, compared to 56 million mt in the whole of 2019, as reported earlier.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
Copyright, Oil Price Information Service
Record-high fuel margins in March led to retailers nearly tripling profits from selling gasoline before demand started to plummet due to the coronavirus disease 2019 (COVID-19), exclusive OPIS data shows.
Still, even as gasoline demand across the nation was slashed by nearly 50% during the peak of COVID-related shutdowns, station profits on gasoline sales continued to significantly outpace 2019 levels because of the high margins, data from OPIS' MarginPro and DemandPro show. During the first 17 weeks of 2020, U.S. retailers saw a total average gross profit per station on gasoline sales of $116,210, compared to $67,249 during the same period in 2019.
Weekly gasoline profits are now starting to come back into line with 2019 levels. Margins have returned to levels seen before the start of the price war between Saudi Arabia and Russia, which led to the crash in the prices of crude oil and refined products.
While still significantly behind levels seen at this time in 2019, gasoline demand is also beginning to recover as more states ease travel restrictions put in place to slow the virus' spread. OPIS' calculations are based on national averages, with retailers in different regions seeing differing impacts.
Gross margins shot up in March as declines in retail fuel prices failed to keep pace with the price war-related drop seen by crude oil and refined products.
The front-month contract for RBOB futures on the NYMEX exchange, which had been trading as high as $1.66/gal in February, hit a recent low of 49.47cts/gal on March 23 - a drop of about 70% -- before slowly climbing back to average 89.66cts/gal last week.
During the first week of February, gross retail fuel margins in the United States averaged 28.7cts/gal with the estimated gross profit per station on gasoline for the week at about $4,646, according to OPIS data. That compares to an average $3,736 for the same period in 2019.
Margins began to increase during the week ending March 6, when they went from 28cts/gal the previous week to an average 32.8cts/gal and then an average 53.9cts/gal during the week ending March 13. During that time, average station gasoline profits rose from $6,509, to $10,680. That's much higher than last year, when gas station profits climbed from $3,359 to $3,703 in the first two weeks of March.
Weekly gasoline profits reached their peak during the week ending March 15, with OPIS estimates showing them hitting $11,989 per station compared to $3,010 during the same week in 2019, an increase of more than 298%.
But at the same time, sales began to drop off as concerns about COVID-19 grew.
OPIS DemandPro data shows that U.S. demand, which had been running about 2% to 3% off 2019 levels in the opening months of 2020, crashed from a year-on-year deficit of 2.4% during the week ending March 16 to 24.1% the week ending March 23 and then 46.5% the week ending March 30.
National gasoline sales bottomed out at 49.1% behind 2019 levels during the week ending April 13. High margins shielded retailers from the impact of this precipitous decline, with retailers seeing profits of $9,582 during the week ending March 22 with margins averaging 76.4cts/gal, compared to profits of $3,615 during the week in 2019.
Profits were $8,610, up from $3,550 in 2019, for the week ending March 29, with margins averaging 86.9cts/gal. Average station gasoline profits were nearly double 2019 levels -- $7,423 with margins of 76.5cts/gal compared to $3,885 - for the week ending April 12 - just as retailers were seeing peak demand destruction.
Average gross margins in the United States hit an all-time high of 95.5cts/gal on March 23. Prior to this year, the previous record margin had been 59.3cts/gal. That record had been set on Oct. 6, 2008, at the start of the global financial crisis that led to the great recession.
Profits remained strong through April, with the week ending April 19 bringing average gasoline profits of $7,035, compared to $3,976 a year ago, on margins of 67.5cts/gal with demand off 47%. Profits for the week ending April 26 were $6,010, up from $4,658 a year ago, on margins of 61.2cts/gal and demand lagging 44.5%.
While it is still too early to estimate the average gasoline profits seen by retailers in May, the trend of falling margins and rising demand has continued, with margins during the week ending May 4 averaging about 49.1cts/gal and demand off nearly 41% compared to 2019 levels. Gross margins on Monday were averaging 30.5cts/gal.
Though margins have remained strong even as the price of gasoline has slowly dropped, the decline in the overall cost of filling up a car's tank and the steep drop in sales is hitting credit card companies, which charge a percentage fee based on the transaction cost, OPIS data shows.
Credit card revenue was slightly ahead of 2019 levels at the start of 2020 but dropped sharply as retail sales slipped due to the pandemic, according to OPIS estimates. The OPIS estimates assume the companies receive a 2% fee, known as a swipe fee, for each transaction and about 75% of fuel sales are paid for with credit or debit cards.
OPIS estimates weekly credit card company revenue hit a year-to-date high of $13.6 million on Jan. 12. That's compared to last year's January to February high of $13.77 million. Revenue continued to climb through March and April in 2019, but that's not the case this year. In 2020, revenue slid steeply after the start of March and is only slowly beginning to recover. Weekly credit card company revenue from gas station sales fell to a low of $5.46 million during the week ending April 5 and had only climbed to $6.04 million during the week ending April 26. That's compared to $16.68 million during the same week in 2019, according to OPIS estimates.
Overall, year-to-date credit card revenue from gasoline sales through April 26 is about $44.63 million, or approximately $66.68 million behind where it was at the same point in 2019, according to OPIS.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Steve Cronin, scronin@opisnet.com;
--editing by Donna Harris, dharris@opisnet.com
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Some Northeast Asian liquefied natural gas (LNG) buyers have re-emerged since last week for summer cargoes, nudging the region's landed prices of the super-chilled fuel back above the psychological threshold of $2/MMBtu.
Front-month June landed Northeast Asian LNG prices rose to $2.3/MMBtu, 16.5% higher than the previous trading day and 24.3% more than at the start of last week on April 27, according IHS Markit OPIS assessments.
June prices were supported by a combination of increased demand due to bargain hunting and last-minute short-covering, as well as tighter supply due to sellers preferring to float their June cargoes into July to take advantage of an inter-month contango of around 50¢/MMBtu.
July, on the other hand, benefited from generally lower prices and seasonality, with bargain hunters stocking up early for the peak summer month, when hot temperatures prompt more energy demand for air-conditioning.
The sudden surge in demand for summer cargoes could be seen in the number of buy tenders issued since late last week. For the second-half June delivery window, China's Foran Energy is due to award a tender on Tuesday for a late-June arrival parcel, while a South Korean buyer could be negotiating for a second-half June lot.
For first-half July, India's Reliance bought a cargo at around $1.85/MMBtu, while a second Korean buyer could be seeking an early July cargo, trading sources said.
For second-half July, China's Guangdong Energy (Yudean) closed a tender on May 8 for a July 23 delivery cargo, while Thailand's PTT is due to award a tender for a late-July arrival on May, they said.
In contrast, there only two sell tenders were issued, with Russia's Sakhalin awarding three July-loading parcels on May 8 at around $2.5/MMBtu, while Brunei offered 2-3 July delivery cargoes in a tender due to be awarded on May 12.
Some traders believe that recent low prices have lured bargain hunters and whetted extra buying appetite.
"Prices below $2/MMBtu were just not sustainable for most producers who need at least $3/MMBtu to break even. I think we have bottomed out, so more people came out to buy," said a Chinese trader.
But others warned against seeing the higher prices as green shoots in the embattled LNG market, where front-month prices are still less than half of the $5.3/MMBtu at the start of the year due to demand destruction caused by the coronavirus disease 2019 (COVID-19).
"I question if this recovery can be sustained. The fundamentals are still so weak over the longer term and unless we see more shut ins or an abnormally hot summer, prices have little support," said a trader in Northeast Asia, adding "The June contract will roll over in a few days and it remains to be seen if prices will continue to rise beyond that."
Several suppliers shared his bearishness, having recently issued market guidance pointing to expectations of lower sales in the second quarter, including Shell, which said it expected to cut LNG production to 7.4-8.2 million mt during the April-June quarter, 12.2% lower than the previous quarter and 9.9% less than a year ago.
Some suppliers have seen their pre-sold long-term volumes being turned back by Asian customers, who have requested for deferments and contractual downward quantity tolerance (DQT) exercises to manage their own brimming inventories.
A spate of cargo deferments and DQT exercises by some buyers in Japan and South Korea could have resulted in a fleet of around 15 unladen project vessels belonging to Qatargas (QG) idling near its Ras Laffan port, the sources said.
Over in the U.S., the biggest number of cancellations of long-term cargoes seen in the past few weeks more than highlight current weak fundamentals. Offtakers have opted to forgo more than 20 June-loading cargoes from U.S. liquefaction plants, even though they still had to hand over an above-$2/MMBtu tolling fee.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Carrie Ho, Carrie.Ho@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com.
Copyright, Oil Price Information Service
Saudi Aramco unexpectedly raised its June crude oil monthly official selling price (OSP) to Asian refiners, suggesting a confidence in the region's demand recovery that's backed by strong Chinese import volumes and a significant narrowing of the Dubai time spread, said market sources.
The Saudi Arabia state-run oil giant increased the price of its biggest crude blend, Arabian Light, by $1.40/bbl to Asia compared with initial market expectations of a reduction of $2-$3/bbl, which became less and less convincing as oil market fundamentals improved, they said.
Tracing the mood of the market, one trader pointed out that at the start of April a dismal, almost Armageddon-like, view of the market emerged as supplies increased exponentially and demand destruction inflicted every major fuel consumer.
"Crude was trading at huge discounts, ending in the negative price on WTI," he said. "Then the OPEC+ output cuts started to impact, suppliers were telling us of 20%, 30% cut in volumes and the contango started to come. All of which looks like a perfect V-shape recovery.
Unlike the wider economy, many sources said that the crude oil market was reflecting a V-shape recovery as countries relax lockdown measures put in place to control the spread of the coronavirus disease 2019 (COVID-19).
China, which was the first nation to come through the worst of COVID-19, has rolled back much of its strict lockdown measures and is recording a steady, consistent rebound in gasoline, diesel and jet fuel demand as road and flight restrictions are lifted. Industries have also cranked up operations as workers make their way back to factories.
"Gasoline and diesel consumption is almost back to 95% of last year's levels, said Feng Xiaonan, IHS Markit downstream analyst in Beijing, which are based on retail fuel sales figures.
Chinese refiners, especially independents, have raised their throughput to take advantage of a crude oil floor price of $40/bbl that is used by the government to set local gasoline and diesel prices, she said.
"The independents are benefiting the most from this floor price and are running at higher levels than last year," Feng said, adding independents generally return a lesser amount by way of windfall taxes to the government than national oil companies because their ex-refinery prices are typically lower.
Refinery runs in China are expected to increase to at least 67% of capacity in May, according to preliminary estimates from IHS Markit compared with typical rates of around 77% prior to COVID-19. Operations dropped to 55% in February before recovering to 60% and 65% in March and April, respectively, IHS Markit data show.
The lower run rates suggest that a lot of China's crude oil imports in the first four months of this year have probably ended up in storage tanks, the capacity of which was severely underestimated by industry watchers, said Feng.
Customs data showed imports in April reaching 42.8 million mt, or 10.4 million b/d, and took the tally for the first four months of the year to 170 million mt, which works out to an unexpected 3% gain from the same period a year ago.
"The Chinese government are asking refiners to import as much as they can.
China may have much more crude in storage than people expected, it could be as much as 30% of imports going into storage," Feng said, referring to arrivals in the first four months of the year.
Aside from China, fuel demand in other major economics such as the United States and Germany are also showing signs of recovery as motorist are allowed to take to the streets, which is being reflected in higher refinery runs.
One measure of the optimism sweeping the Asian market can be seen in the region's benchmark Dubai crude time spread.
More than a month ago, the front-month Dubai spread fell to as low as $4/bbl in contango for May/June before recovering to minus $1.20/bbl with June/July as the new front month about a week ago. This spread narrowed to $0.60/bbl in contango this week with the new July-August months, one trading source said.
"The Dubai spreads have strengthened a lot. It is reflecting the improved fundamentals we are seeing in the market," the source said.
The improving market balance will hit a buffer in the coming days as there are still lot of crude oil stored on board tankers and filled to the brim in onshore tanks that need to be cleared out before a sustained rally can be envisaged, market sources said.
They said a narrowing of the spread has made the contango-storage trading strategy uneconomical even as very large crude carrier (VLCC) rates slumped to levels not seen since early April when the market was flooded as Saudi Arabia and other Middle East producers opened their oil taps and slashed OSPs after an OPEC+ output talk broke down.
The low freight rates and continued Chinese appetite for crude oil is likely to draw unsold cargoes from the North Sea and Latin America to East Asia, they said.
"China is buying a lot of Brazilian and other Latam crudes and will turn to North Sea next," said one trading source, adding that huge cuts to Russian Urals output on the back of higher European refinery runs should keep flows of this medium-sour grade away from Asia low unlike in end-March/first half April.
Fixture lists released on Friday look to back this view with VLCCs booked to load cargoes from Brazil, Hound Point and Southwold in the UK.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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When Texas regulators on Tuesday shelved plans to impose crude oil production cuts throughout the state, supporters praised the move, saying global markets will impose their own limits on production.
But even as energy demand begins to pick up amid the easing of restrictions aimed at fighting coronavirus disease 2019 (COVID-19), the question remains just how deeply and for how long global oil production must be slashed to return markets to balance and ease a critical shortage of oil storage capacity.
Markets are already pricing in the easing of supply, as an agreement by OPEC and its allies to reduce production by 9.7 million b/d went into effect May 1.
That agreement, along with optimism that the United States and other nations are beginning to emerge from COVID-19 lockdown, boosted the front-month price of West Texas Intermediate crude oil more than 100% between April 28 and May 6, from a low of $12.34/bbl to a high of $26.74/bbl
Global crude oil demand is expected to continue to remain significantly depressed in coming months -- IHS Markit projects a year-over-year decline of 22 million b/d in the second quarter of 2020, and the International Energy Agency expects average demand for the year to contract by 9%, or 9 million b/d.
IHS Markit is the parent company of OPIS.
Analysts are now pondering how much production must fall and for how long to rebalance markets. The even larger question is just how those cuts will be accomplished.
Jim Burkhard, vice president, and head of crude oil market research for IHS Markit, said the storage shortage ensures "the world is going to see the biggest production cuts ever" in coming months, with global oil output falling by as much as 17 million b/d in the second quarter.
"It comes down to this: If you can't sell it, you can't store it, then you can't produce it," Burkhard said.
In April, both the IEA and IHS Markit warned that global oil production would likely overwhelm the 1.2 billion bbl of global crude oil storage capacity. Even with the OPEC+ agreement, Burkhard this week said supply continues to outstrip demand and threaten storage.
This dynamic was reflected in the underwhelming reaction to the OPEC+ cuts.
Even before the cuts went into effect, investment bank analysts were speculating that the group might announce a second round of reductions either at its June meeting or even before the gathering.
That's unlikely, said Burkhard, unless economic conditions force the cartel's hand.
"If price were to fall to $10, then yes, there would be consideration of deeper cuts," he said. "But the deeper cuts would also reflect reality -- if you can't sell it, it makes sense to frame it as an organized cut to boost market confidence."
What's more likely is that OPEC+ will sit tight and companies, moved by market forces, will implement cuts without being forced by government mandates, Burkhard said.
That the Texas Railroad Commission was even considering production curtailed by 20% before rejecting the plan was an indication of how difficult market conditions are, he said.
Even without mandates, cuts are being made, according to longtime oil economist Phil Verleger. In his Notes at the Margin report this week, Verleger said U.S. production might already be down by 2.7 million b/d, to about 10 million b/d, as producers shut in wells that are uneconomical to operate or because they couldn't find oil buyers in this time of record-low demand.
Verleger said his research indicated that U.S. production might need to decrease by 4.5 million b/d, or 35%, "to maintain the efficient operation of the U.S. crude logistical system."
Recent weeks have seen announcements of large cuts in United States, with much of those cuts in shale fields, where production costs are generally higher than those at conventional wells. ConocoPhillips is slashing production 265,000 b/d in May and planning cuts of 460,000 b/d in North American production starting in June. ExxonMobil has said it will shut in about 100,000 b/d of oil equivalent in the Permian Basin. Chevron will curtail 200,300 b/d of oil equivalent in May and continue that through June. Continental Resources has shut most of its wells in North Dakota's Bakken play, according to reports.
Rystad Energy said its analysis indicates 616,000 b/d of U.S. production will be shut in during May and 655,000 b/d in June.
"Given the severity of the current market situation and significant production curtailments announced already since April, shale producers are not relying on natural decline but rather are choosing more drastic measures to reduce their output substantially and fast," said Veronika Akulinitseva, Rystad vice president, North American shale and upstream.
Meanwhile Norway, Europe's largest oil producer, is reducing production by 250,000 b/d in June and then to 134,000 b/d, or about 8% of its 1.7 million b/d production, through 2020.
Cuts are likely to stay in place awhile. All the oil in storage is enough to supply global demand for about 90 days, Burkhard said. While production cuts and growing demand will draw those supplies down, the length of time it takes depends on how steeply demand rises and where production levels remain.
"May and June are probably going to be where surplus is at its worst," Burkhard said.
Verleger sees U.S. production remaining constrained through 2020 unless the pandemic eases. The economist, however, is not optimistic about a fast rebound.
Meanwhile, an increase in global demand poses its own threats. Producers would be tempted to increase output, drowning any price recovery in a wave of new oil crashing, Burkhard said.
The analyst said the OPEC+ agreement, plus reductions by private companies, resulted from a convergence of interest among producers when the price of oil sank too low. It's an unusual situation based on the current, unusual circumstances.
"As prices rise, that convergence is going to disappear," Burkhard said.
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--Reporting by Steve Cronin, scronin@opisnet.com;
--editing by Barbara Chuck, bchuck@opisnet.com
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Repsol cut utilization rates at its refineries to 80% last month, reducing jet fuel production amid a plunge in demand, CEO and executive director Josu Jon Imaz San Miguel said Tuesday.
Repsol, Spain's largest refiner, cut jet output without shutting down any refineries, the CEO said in a first quarter earnings call yesterday. In comparison, refinery utilization rate in Spain was 90% in 2019, according to IHSMarkit data.
The slump in aviation fuel demand comes as flights are grounded and many countries enforce travel restrictions to curb the spread of the coronavirus disease 2019 (COVID-19) pandemic.
Repsol shut down the ISOMAX, a hydrocracking unit in Tarragona that produces aviation fuel. It reduced fluid catalytic cracker (FCC) run rates at refineries in Bilbao and Puertollano. The FCC at the Coruna refinery was now shut, Josu Jon Imaz San Miguel said. Maintenance at the Coruna refinery FCC began in January, initially for two and a half months. The unit was still undergoing maintenance by March 30, operating at reduced capacity, according to a Repsol spokesperson at the time.
Many refineries throughout the Mediterranean region have cut jet production due to the lack of demand, and aviation fuel prices in Europe have slumped. The crack spread - a measure of the profitability of the fuel - for jet barge cargoes loading in the northwest European hub of Amsterdam-Rotterdam-Antwerp flipped into negative figures in early April, plummeting to the low of minus $8.88/bbl on Tuesday. By comparison, jet barge crack spreads were pegged at plus $16.73/bbl on January 2.
Repsol has five refineries in Spain. They are Coruna (120,000 b/d), Puertollano (157,000 b/d), Tarragona (160,000 b/d), Petronor (220,000 b/d) and Cartagena (220,000 b/d). The total refining capacity in Spain is 1.4 million b/d, of which Repsol accounts for half, according to IHS data.
OPIS contacted Repsol for comment Wednesday but did not hear back at the time of publishing.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Nandita Lal, Nandita.lal@ihsmarkit.com, Selene Law, Selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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June RBOB prices today surpassed 90cts/gal, representing a gain of about 140% from the 37.60ct/gal low witnessed on March 23.
The increases have been driven by statements like "Americans are driving again," or in some cases by projections that the worst of demand destruction has passed, pointing toward a return to normal driving-season consumption, perhaps later this month.
In addition to the motivation of "cabin fever," a few analysts are predicting that vehicle miles traveled could be juiced by aversion to flying and avoidance of mass transit.
June through August 2019 is a tough act to follow in the U.S., however, since those four months delivered average gasoline demand of 9.595 million b/d.
The most recent four-week average for domestic gasoline supplied from the U.S. Energy Information Administration (EIA) is just 5.329 million b/d, compared with 9.466 million b/d in the same period of 2019. The OPIS Demand Report, a weekly retail gasoline volume survey of more than 15,000 unique sites, however, hints that stateside sales have occasionally dropped below 5 million b/d, hitting a low of 4.594 million b/d for the week ended April 11. Any way one looks at it, a recovery to statistics bearing any resemblance to 2016-2019 numbers is an experiment in regaining altitude.
During the worst of the stay-at-home restrictions, OPIS measured gasoline demand on a same-store basis down 49.1% from year-ago levels. In retrospect, the week ended April 11 does appear to represent the bottom, but the climb thereafter has not exactly been frenetic.
Gasoline demand from June through September last year averaged 9.595 million b/d. If the rebound took consumption back to 75% of normal, it would imply a domestic demand figure of less than 7.2 million b/d. If social distancing and fear of the coronavirus disease 2019 (COVID 19) were significantly eased and the recovery number was 80%, demand of 7.676 million b/d would result. Only if demand destruction eased to, say, 10% would the U.S. again require 9 million b/d of motor fuel.
Chain retailers do cite a mixed recovery for gasoline in the 50 states.
Michigan appears to be the state hardest hit by a combination of COVID-19 and a struggling economy, with demand destruction measured in the mid-60s. Most recent data suggest that the state has bounced off its bottom, but the amplitude of the bounce is only about 2%.
More robust recoveries in consumption are reported for Arizona, Florida, Georgia, Kentucky, Mississippi, Missouri, Nevada, Ohio, Oklahoma, Texas, and Virginia, but OPIS cannot find a single instance where the jump was beyond single digits. Only four states can be identified with year-on-year demand destruction of less than 30%, and they are Arizona, Georgia, Kentucky and Texas. Georgia and Texas have been among the states most aggressively reopening, so they deserve scrutiny in the weeks ahead.
Wildcards for gasoline supply balances this driving season may come from offshore. May 2019 imports of motor fuel were an unusually hefty 1.148 million b/d, including 1.03 million b/d of blending components and 118,000 b/d of finished gasoline. Exports of finished gasoline last May averaged 743,000 b/d.
Both numbers are likely to be lower in the next four weeks, particularly on the import side. But if COVID-19 spreads through Central and South America, perhaps one less cargo per day of gasoline might move south from complex Gulf Coast refiners.
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--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Supplies of ethanol, a key ingredient for hand sanitizers that have been in exceptional demand during the coronavirus disease 2019 (COVID-19) pandemic, will tighten in Europe due to planned maintenance at the Ineos-operated Grangemouth complex this week, sources told OPIS today.
Ineos is Europe's largest producer of synthetic ethanol due to Grangemouth's two units, which produce a combined 300,000 metric tons/year of the product.
"It should have gone down three or four weeks ago, but because of the coronavirus pandemic and the fact that ethanol is one of the main components of hand sanitizer, it has been kept going," a source told OPIS. "It's needing some maintenance."
The source added that Ineos aims to complete the work in less than two weeks.
"They are trying to get it back online as soon as possible given the demand," the source said.
Planned turnarounds at the Petroineos-operated 210,000-b/d refinery and the Ineos-operated petchems complex, both situated in Grangemouth, Scotland, have been cancelled due to the pandemic, OPIS reported earlier.
Sources also told OPIS that construction work set to begin on a combined heat and power plant at Grangemouth in the fourth quarter has been postponed by Ineos. The cost of the construction work was pegged at around 350 million pounds sterling.
Ineos has been one of a number of private sector companies, ranging from oil companies to beer producers, who have responded to the pandemic by producing medical-grade hand sanitizers.
Announcing the successful construction of a hand sanitizer plant in the northeast of England, the company said in a statement at the end of March:
"Ineos is the leading European producer of the two key raw materials needed for sanitizers - isopropyl alcohol and ethanol, producing almost 1 million tons.
The company is already running these plants flat out and have been diverting more of this product to essential medical use including in the new Ineos factories."
Similar hand sanitizer factories have been built by Ineos in recent weeks at Herne in Germany and Lavera in France.
Ineos did not respond to e-mails and phone calls concerning ethanol production at Grangemouth. The company also declined to comment on OPIS stories relating to the cancelled turnaround work scheduled for April.
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--Reporting by Anthony Lane, alane@opisnet.com;
--editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Phillips 66 has reduced utilization at its oil refineries to better match fuel demand that has been floundering because of the coronavirus disease 2019 (COVID-19) pandemic, and it is taking production where refining margins lead it. But the petroleum refiner and marketer also offered up some interesting supply indicators to monitor as recovery signals.
In its May 1 earnings conference call, the company updated its view of refined products demand in its system so far in 2020, noting that gasoline demand destruction in the U.S. that had reached as much as 50% had eased to about 35%.
Demand destruction in western Europe that had reached 70% has lessened to about 50%, according to Brian Mandell, executive vice president of marketing and commercial.
"We got down to about 65% (refinery) utilization when demand was at its worst," he added.
Phillips' short-term view of U.S. gasoline demand is buoyed by expectations of 16 states lifting stay-at-home policies and rising public displays of opposition to the policies.
"I think being in quarantine and being cooped up and just going crazy in the house, people are going to want to get out," CEO Greg Garland said, "and that should actually bring gasoline demand back pretty good."
The Phillips 66 senior management team -- which asserts that work-commutes comprise roughly 35% of U.S. gasoline demand -- sees businesses getting back to work as powering demand recovery.
Asked how, from a behavioral standpoint, Phillips 66 anticipated "coming out the other side of" COVID-19 fuel demand destruction, Executive Vice President, Refining, Robert Herman said that the company was "going to look for a pretty strong and pretty stable demand signal from the market, before we start ramping up units that might be idled right now."
Invoking an engineering metaphor and the latest weekly EIA report, Mandell said the East Coast (PADD1) market was signaling still much-reduced consumption of gasoline for the U.S. as a whole.
"We have the addition of a flywheel for gasoline, because PADD 1 is an import market," he said. "If you take a look at just the last DOEs, 160,000 b/d of gasoline came into PADD 1. That's about 25% ... of what typically comes in (at this time of year)."
"We won't overproduce and that will keep us from filling up ... so we don't have any concerns on clean products," Mandell added.
The company said that its exports of refined products -- which increasingly play a role in U.S. refiners' production profiles, particularly those to Central and South America -- averaged 160,000 b/d in the first quarter, 3,000 b/d higher compared to the fourth quarter of 2019, but it offered little else about that part of its business.
In a late-March conference call with analysts, Phillips acknowledged that term customers in Latin America -- who were expressing concern about possible demand impacts due to COVID-19 -- had begun asking about backing out of refined product cargo commitments.
Jeff Dietert, head of investor relations, noted on Friday that because Latin America was among world regions only recently affected by the pandemic, "we're seeing a little bit of weakness there."
"But it's really a holistic approach to demand overall that we're using as a guide to run our refineries at the rate that matches that recovery," he added.
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--Reporting by Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Frank Tang, ftang@opinset.com
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Swedish demand for diesel and gasoline in April was likely 10-20% lower year on year, OPIS has learned, offering a potential pointer to demand levels in other Western countries as they transition from sweeping lockdowns to combat the coronavirus disease 2019 (COVID-19) pandemic to less-restrictive measures.
Sweden has attracted some praise but mainly fierce criticism from around the world for its relatively "light-touch" measures to combat the pandemic that have allowed businesses, cafes and many schools to stay open.
Instead of pulling down the shutters on business life and social activities, the government and health authorities have asked citizens in the historically high-trust society to respect social-distancing guidelines while in public and to work from home if possible.
Similar measures now appear likely to be taken across European nations eager to restore economic activity, as infection rates fall and government budget deficits swell.
Johan Andersson, chief executive officer of the Swedish Petroleum and Biofuels Institute (SPBI), which represents Sweden's oil industry and collects consumption data, confirmed to OPIS that year-on-year road fuel demand in April had fallen to a far lower extent than in the rest of Europe.
Referring to declining demand for diesel and gasoline in April, Andersson said: "I've heard numbers for European countries between 30-70%. We are probably in the 10-20% region. This is based on conversations with our member companies who have told us that's likely to be the effect in April."
The pandemic and social-distancing measures have prompted sharp falls in public transport use, said Andersson, resulting in those unable to work from home opting to travel by car.
"I live 20 miles outside of Stockholm. I normally go by bus to the office, and those buses are now empty apart from transporting (healthcare workers)," he said. "People are being told not to use public transport, which of course leads to many more people driving themselves (into) the big cities of Stockholm, Gothenburg and Malmo.... That's having a massive impact on fuel consumption," Andersson added.
The SPBI will release its road fuel demand data for April in mid-May, Andersson told OPIS.
The institute's CEO was reluctant to engage in predictions for future road fuel consumption in Sweden, but noted the potential for domestic holidays to offer a fillip to demand.
"Quite a few industries are opening up again in May, which means that we should see more transportation, people driving.... I think we will see subdued demand for an extended period of time," said Andersson. "On the other hand, you can see that people are discouraged from flying on holiday this summer, which means that many will drive in Sweden for their holiday, so that could compensate."
Swedish diesel demand in March actually managed to defy the global pandemic and register a year-on-year rise, SPBI data show.
Retail sales of diesel in March nudged higher by 1.4 million liters, to 569.2 million liters, a 0.2% year-on-year rise. Gasoline sales in the same month were down 2.3% y-o-y to 223.4 million liters, but first-quarter gasoline sales were slightly higher than in Q1 2019, said the SPBI.
Andersson said he was "mildly surprised" that diesel demand rose in March, but pointed out that Sweden's more modest measures to combat the pandemic, such as closing universities and high schools, were implemented on March 15.
Furthermore, demand from Sweden's forestry and agricultural sectors was healthy, and citizens took advantage of plummeting prices to fill tanks, he suggested.
The less-exacting measures taken in Sweden will not spare the country from experiencing a crushing recession, the country's central bank said last week.
The Riksbank forecasts that the economy, which is heavily reliant on exports, will contract between 6.9% and 9.7% in 2020.
Despite the absence of a severe lockdown, Sweden's per capita COVID-19 infection rate is close to the European average and lower than in the U.K., but higher than in other Nordic nations and slightly higher than in the United States.
The government has taken a backseat in Sweden's handling of the pandemic, with the response being led by the country's Public Health Agency and its chief epidemiologist, Anders Tegnell.
Tegnell has argued that the country's approach to the pandemic is more sustainable, a view that received cautious backing from the World Health Organization (WHO) last week.
"If we are to reach a 'new normal,' in many ways Sweden represents a future model," said Mike Ryan, WHO's emergencies expert.
Sweden does, however, enjoy certain advantages over other countries in pursuing its present course of action. The country's population of 10 million people is dispersed over a landmass of 450,000 square kilometers. By contrast, the more urban U.K. has a population of 65 million people and a landmass of 242,000 square kilometers.
Moreover, social-distancing is easier to achieve in Sweden given that more than half of all households there are single-person.
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--Reporting by Anthony Lane, alane@opisnet.com;
Editing by Barbara Chuck, bchuck@opisnet.com
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India posted an increase in transportation fuel exports in March due to a slump in domestic demand amid lockdown measures put in place by Indian authorities to curb the spread of the coronavirus disease 2019 (COVID-19).
The nation went on a countrywide 21-day lockdown on March 25, which has now been extended to May 18, leading to concerns of further fuel demand destruction in the coming weeks, market sources said.
A total of 4.588 million mt of transportation fuels (gasoline, diesel, jet fuel) were exported in March, compared to 3.938 million mt in February, or up 16.5% month-on-month, data from Petroleum Planning & Analysis Cell (PPAC) showed.
Gasoline exports rose 11.1% on-month in March to 1.141 million mt, whereas local demand in the same period fell 14.1% to 2.156 million mt, the lowest since February 2018, PPAC data showed.
Diesel shipments gained 24% from the previous month to 2.958 million mt.
Domestic consumption for diesel was hit hard due to its duality of uses in both industry and transportation sectors. It fell 21% from the previous month to 5.651 million mt, the lowest since September 2016, according to the PPAC data.
Jet fuel exports in March, on the other hand, shrunk 7.04% from the previous month to 488,000 mt despite bearing the brunt of the demand destruction with the suspension of both domestic and international flights.
That comes as refiners were unable to find homes for their export cargoes with COVID-19 also crippling global demand.
This is also the first time in at least five years that jet fuel in March recorded a month-on-month decline.
"Exports in March are usually higher compared to February as refiners try to clear as much of their inventories as possible before the close of financial year," a trader said.
In the past five years, from 2015 to 2019, March exports recorded on-month increases of 14.4%, 24%, 50.8%, 16.7% and 50.2%, respectively, IHS Markit OPIS records showed.
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--Reporting by John Koh, John.Koh@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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April was a cruel month in the petroleum supply chain thanks to coronavirus disease 2019 (COVID-19)-inspired shelter-in-place requirements as well as record crude oil output from Saudi Arabia, Russia and the United States. Some number-crunching by OPIS suggests that it easily stands as the least expensive month in the 21st century in terms of gasoline costs.
Using the most recent Energy Information Administration (EIA) numbers and the average unleaded gas price in a cost equation, OPIS calculates that the total April motor fuel bill was just $12.4 billion, or some $20.7 billion beneath the April 2019 cost.
That assessment, however, may represent an overstatement. Trading companies put away extra gasoline early in the month to take advantage of an unprecedented contango play for storage, and the amount of fuel pumped was probably lower than EIA numbers, which merely measure gasoline moving from reportable to non-reportable storage.
And average prices were easy to beat. Many markets regularly saw aggressive Big Box stores such as Costco sell fuel for 35-50cts/gal below market averages. The distance between the most aggressive street prices and the average street price was 50cts/gal in a number of states, and the gap often topped $1/gal in California.
The factor clearly most culpable for the record cheap month was demand destruction. EIA statistics issued so far suggest the lowest monthly consumption since January 1971 when inclement weather pushed demand down to 5.264 million b/d. Records suggest that one has to go back to 1967, several months ahead of the "Summer of Love," to find an April where consumption was below this month's likely final figure. In both cases, the standard motor fuel in the country was an 89-octane leaded gasoline.
May is almost certain to begin with some higher numbers. By midday Thursday, most U.S. gasoline blendstocks were up by about 14cts/gal since Monday's closing numbers, and indeed the average retail price moved up 0.5cts/gal.
Some other highlights in a month that may set a low standard for years to come:
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--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Refining margins for very-low-sulfur fuel oil (VLSFO) in the trading hub in and around Rotterdam have plummeted to negative territory for the first time this year amid a decline in demand caused by the coronavirus disease 2019 (COVID-19) pandemic, OPIS data shows.
The crack, a measure of the spread between the flat price versus rolling Brent, for VLSFO barges, loading in Rotterdam, was at minus 92cts/bbl on April 29, using a density converter of 6.35.
"I'm not surprised to see VLSFO cracks narrowing as stocks were building prior to January, then demand started to fall due to the virus but production increased, so VLSFO supply is clearly outpacing demand," said Anton Shamray, senior research analyst at global bunker trading company Integr8 Fuels to OPIS Thursday.
As crude prices seem to be going up slightly, the ample supply of VLSFO and the falling cracks will likely slow down production in the near future, Shamray said.
"Demand for marine fuels is indeed weak globally compared to say the fourth quarter of 2019 and we are hearing it's down 7-10% this year to date," he added.
Marine fuel demand is estimated to be down by around 270 million metric tons annually to date.
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--Reporting by Stacy Irish, stacy.irish@ihsmarkit.com;
--Editing by Paddy Gourlay, patrick.gourlay@ihsmarkit.com
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In northwest Europe, LPG cargo trade over the course of April began to react to the coronavirus disease 2019 (COVID-19) related lockdowns across Europe and resulting fall in demand for products and goods. The effects on LPG were latterly felt the most in the petrochemical feedstocks sector and followed an abrupt fall in demand for distillates, mainly gasoline.
Overall LPG trade was down by an estimated 23% compared to March, with intake as petrochemical feedstock down by 19% at 515 kt. Despite the intake fall, the level was considered fairly robust, as the same period saw more severe demand falls in other products sectors such as gasoline and naphtha.
The reduction in LPG imports, particularly the U.S. Gulf Coast, to the feedstock pool was clear in the figures for local demand from that sector. A breakdown of the origin of LPG intake as feedstock in April saw 65% coming from the North Sea, up from 45% in March, 22% from the U.S. East Coast, up from 17% last month, 9% from the U.S. Gulf Coast, down from 32% and 4% from the Russian Baltic, down from 6%.
By the start of April, propane's spread to naphtha had already flicked to positive, as naphtha demand was deeply affected by a demand crash for gasoline.
Starting the month at plus $49/t, the spread hit a wide plus $131/t by April 21, later narrowing slightly. For comparison, March had seen propane/naphtha open at minus $105/t.
For LPG, the time lag from end-users rolling back poor demand into feedstock intake was estimated at around two weeks. Import flows started to reduce by mid-April, with at least four TOT re-sales taking place -- all for May dates.
At or about the same time, a number of cargoes initially on the horizon for Europe subsequently shipped to other destinations, the last to do so in the final days of April.
By mid-April, demand for ethylene fell substantially enough to pull spot prices to half the level of the term price, the latter set at 720 euros/t for the month. Underlying demand had already reduced the term price in April by 22% from its March level, at 920 euros/t. Ethylene exports, which reflected the implied local demand fall in March, fell to zero for April. March exports had spiked to 90 kt -- some four times higher than a normal month.
LPG exports out of the region were 50% up on March, with cargoes moving to the U.S. East Coast, Morocco and to India. Exports to Italy and to Turkey did not appear. The retail and refining sector intake fell by more than half to an estimated 130,000 tons.
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--Reporting by Dermot McGowan, dmcgowan@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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April exports of ultra-low-sulfur diesel from key Baltic ports have discharged into storage tank farms, outside the typical import hubs, as European demand plummets amid a global restriction of population movement, according to market sources and OPIS tanker tracking data.
Over the course of April, oil tankers hauling diesel cargoes from Baltic ports headed as far as Puerto Rico. Scandinavia emerged as a big importer, with sources saying demand there is mainly into caverns for storage, first reported to OPIS as early as end-February.
A long/large range (LR) type 2 vessel, the Cielo di Londra, with a 65,000-ton diesel cargo, on charter to an unknown party, headed to Puerto Rico, after loading in Primorsk on April 6. The tanker reached its destination on April 24, the data show.
About 300,000 metric tons of Baltic diesel went to Sweden this month, while Norwegian, Danish and Finish ports saw an inflow of about 200,000 tons, according to broker data. The three countries have not taken Baltic volumes previously, according to OPIS data.
The larger LR tankers have been booked as floating storage units, according to shipbroker reports, although demand for smaller tankers as inventory storage is lower in comparison. But demand for the larger units has drained the supply of available vessels for spot charters and boosted clean tanker rates across all tanker classes, according to market analysts.
"If indeed about 8-10% of all clean tankers are used for storage now, that removes a lot of capacity and pushes all freights higher," one distillates source told OPIS.
Daily time-charter earnings to transport a refined oil product cargo to the French port of Le Have from Primorsk in Russia, the so-called TC9 route, jumped to $71,782/day on April 27. That's the highest since July 2018 when rates started to be assessed along this route, Baltic Exchange data show.
Overall, the largest importer in April was Germany, taking about 350,000 tons, mainly into Hamburg. But the usual buyers, like France and the U.K. took only a fraction of their typical demand. U.K. imports totaled about 150,000 tons, while earlier this year monthly tallies stood between 400,000 and 600,000 tons.
Only two 30,000-ton cargoes were seen heading to France, where demand spiked earlier in January this year, following country-wide industrial action. This resulted in imports of Baltic diesel cargoes of almost 700,000 tons that month, according to IHS Markit Commodities at Sea data.
Total vessels booked to ship diesel cargoes from all Baltic ports in April, including Primorsk, Saint Petersburg, Ventspils, Ust-Luga and Vysotsk, could add up to just under 2 million tons, but with loading delays and failed tanker bookings, volumes have added up so far to only 1.6 million tons. The port of Primorsk is set to export about 1.41 million tons of diesel to date, slightly under the planned 1.57 million, according to initial loading program information seen by OPIS.
The May loading program for diesel shipments ex-Primorsk shows a 10% month-on-month decrease for planned loadings. That's still about 60% higher from May 2019 levels of 1.42 million tons, according to OPIS data.
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--Reporting by Paulina Lichwa-Garcia, paulina.lichwa-garcia@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Several other oil companies have followed ExxonMobil's lead and inserted language in bulk contracts that specifically outlaws negative prices for gasoline, diesel, heating oil and jet fuel. ExxonMobil was the first company to employ these clauses, and while at least one major commodity trading house rejected the terms, OPIS sources say that other multiple counterparties have agreed to the language.
The move comes less than 10 days after a wild Monday session for an expiring WTI contract on the CME led to transactions that briefly dipped to negative $40/bbl.
A number of U.S. bulk markets typically are fixed at "basis discounts" that call for delivery of fuel versus a NYMEX reference month.
This month, for example, it has not been unusual to see spot deals for Chicago CBOB at discounts of 43cts/gal to 43.5cts/gal off NYMEX RBOB. RBOB prices briefly dipped below 40cts/gal this spring, so theoretically, there are worries about negative numbers as a result of traditional contract arithmetic.
Similarly, Gulf Coast distillate has traded for as much as 31cts/gal under NYMEX ULSD contracts and jet fuel discounts of 30-33cts/gal have been recorded since the coronavirus disease 2019 (COVID-19) wreaked havoc on demand.
In addition to ExxonMobil, OPIS hears that Phillips 66 and Valero have implemented the "no negative" clauses. If RBOB or ULSD futures get pounded, wet barrel numbers at the Gulf Coast or in a Chicago FOB point could flirt with less than zero.
The language viewed by OPIS suggests that under no circumstances would a seller of product have to remit money to a buyer, regardless of the arithmetic between the futures settlement and the basis discount. Unprecedented volatility is cited as is the motivation with sellers realizing that wild futures swings could result in a transaction price below zero. If that happens, the buyer needs to receive the product and the seller is obligated to deliver full contracted volumes. Terms dictate that "in no event" will a seller be liable to pay any amount to the buyer for the buyer's purchase of such product.
Example: If a refiner sold some ULSD on Colonial Pipeline at 30cts/gal under June ULSD futures and those futures settled at 29cts/gal, the contract price would hypothetically be a negative 1cts/gal. Terms would treat the final price as zero, however.
Terms go on to explain that if a final price is less than zero, the buyer remains obligated to receive, and the seller remains obligated to deliver, the full contracted volume of fuel. In no event will the seller be liable to pay any amount to the buyer for the buyer's purchase of the product.
Clauses generally note that the buyer will be required to pay secondary or incremental costs, including freight, storage, handling and other costs applicable to the deal.
OPIS is not aware of any transactions which have yet resulted in negative prices for any refined products, but the plunge into negative territory by WTI puts such possibilities in play.
"Did you ever think we'd be having this kind of conversation about prices?" one products broker asked OPIS, observing that Monday April 20 was a game-changer for traders on both sides of the ledger.
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--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Turkish refiner Tupras is expected by OPIS sources to halt production at its 230,000-b/d Izmir refinery due to weak demand for jet and diesel resulting from the coronavirus disease 2019 (COVID-19) pandemic.
The company has already cut runs at its 113,000-b/d Kirikkale refinery by 50%, sources say.
Tupras declined to comment when contacted by OPIS.
Tupras operates the Izmit, Izmir, Kirikkale and Batman refineries in Turkey, which have a combined capacity of 789,000 b/d.
The company has revised its 2020 production forecast down to 24 million metric tons from 28 million mt, and it has also lowered its sales estimates from 29 million mt to 25 million mt due to a fall in demand.
"Our 2020 expectations, which were disclosed on Feb. 12, are revised due to the global pandemic's negative impact on petroleum products demand and margins, as well as the drop in Brent oil prices," the company said in a filing posted on the Public Disclosure Platform (KAP) website.
"As a result of these changes, our 2020 capacity utilization expectation is revised from 95-100% to 80-85%," it said.
The company's statement revised down its net refining margin forecast to $3-4/bbl from $4.5-5.5/bbl.
Tupras said that the revised forecast was predicated on demand for oil products beginning to return by June, with "normal economic activity resuming from August."
Fitch Ratings revised its outlook for Tupras to negative from stable due to lower demand for fuels caused by pandemic-related lockdowns.
Get daily expert analysis of the Northwest Europe and Mediterranean jet fuel, ULSD and gasoil markets with OPIS Europe Jet, Diesel & Gasoil Report
--Reporting by Stacy Irish, stacy.irish@ihsmarkit.com;
--Editing by Anthony Lane, alane@opisnet.com
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The unprecedented negative price settlement on U.S. crude futures last week has raised the specter of similar incidents for billions of dollars of oil products that are determined by way of netback, forcing sellers to include a negative price clause in their contracts, market sources said.
This previously envisaged scenario is now a concern in the face of two opposing forces -- crumbling demand and soaring freight -- that has led to free-on-board (FOB) prices exposed to the vagaries of the shipping market, which is now a kingmaker in the oil trading business. This is particularly so in the Middle East, whose price is derived from established benchmarks in another location.
"The netback model starts with a depressed Singapore product price and then subtracts a soaring freight rate to derive an FOB Arab Gulf (AG) price," said John Driscoll, a long-time oil trader and analyst who now lectures on energy risk management at the Singapore Management University, adding that the question now is how low the netback value may go.
Driscoll does not think that it would turn negative as was the case in North America.
Price assessments for millions of barrels of Middle East jet fuel and gasoil are done by way of netbacks, that is deducting a freight element from established FOB Singapore prices. This would have been fine, if that was the natural trade route for the AG fuels market.
However, it is not the case anymore compared with around 30 years ago when these principles were first established by price reporting agencies, market sources said.
Trade data and shipping fixtures clearly show that the bulk of middle distillates produced in the Middle East, which has seen an explosion of refining capacity in recent years, are shipped West. Diesel and jet fuel are regularly exported to East and West Africa, as well as in ever growing volumes to Europe, which has been scaling back its refining capacity.
"The relevance of the Singapore netback model has declined while new Gulf refining capacity came onstream; hence, standalone FOB (AG) benchmarks for the Middle East make more sense and better reflect values in multiple export markets," said Driscoll.
"However, traders get comfortable with the price models they know and generally resist change. It may be time for a wake up call," he added.
For example, on April 22 jet fuel prices fell to a low of $14.86/bbl in Singapore, which brought it dangerously close to the freight costs used to calculate the netback AG price, which on that day slumped to $8.40/bbl, according to data from IHS Markit OPIS.
While netbacks used to calculate delivered prices are less likely to run afoul of the soaring freight but such FOB prices for Northeast Asia are also exposed to this issue, especially if the natural flow for the product is the U.S. west coast, market sources said.
Clean freight costs have gone through the roof after numerous tankers were snapped up as floating storage in the face of a supply overhang. For example, the rate for an LR2 tanker carrying 90,000 mt of clean product from the AG to Europe jumped to $8.15 million on Tuesday from $3.7 million on March 24, fixture lists show.
It is unclear as to how the industry would react once the dust settles and the global economy gets back on an even keel following the coronavirus disease 2019 (COVID-19) pandemic.
For now, however, sellers are protecting themselves by inserting a negative price clause in contracts so that they don't end up in the unforeseen situation of having to pay the buyer to take away the fuel that they have sold.
"They are in place to prevent having to pay lifters for lifting the cargoes," said one trading source.
The terms of the contracts are such that if the price drops to negative, it would be reflected as zero in the deal.
Oil are typically sold on a forward basis and is priced off published benchmarks or futures contracts. The pricing period is decided between the parties involved and could range from a typical short two-days on either side of the loading date to an average of the whole month of loading.
Some companies avoid this hassle, which is usually done as a hedge to volatility, and simple buy on an agreed outright, or flat, price.
The oil industry is still coming to grips with the negative settlement chalked up April 20 after May WTI settled down around $56/bbl at negative $37.63/bbl.
The now-expired May WTI soared to finish at $10.01/bbl the following day.
The new front-month June contract lost $4.16/bbl, or 24.6%, to settle at $12.78/bbl on Monday and last traded down $1.06/bbl to $11.72/bbl at around 6:40 pm Singapore time. The market took a beating after U.S. Oil Fund, the largest oil exchange product, said it would shift its holdings to later-dated contracts and sell its June positions.
The latest sharp decline on WTI has raised fears once more that when the front-month contract nears expiry it may again test the negative territory. The negative settlement had led to huge losses among retail investors who were trading this futures contract.
"Those in the physical oil business generally heed supply chain limits and constraints. Oil is a finite commodity and at the end of the day oil moves from point A to point B," said Driscoll, adding that non-commercial investors who traded deliverable futures without physical storage were especially vulnerable.
WTI's historical dive into negative territory may ultimately force traders to reconsider the risks of futures markets. Despite increases in pipeline capacity, line reversals and U.S. President Barack Obama's removal of the crude oil export ban in 2015, Cushing's landlocked status may drive price dislocations in oversupplied markets, the sources said.
"Waterborne benchmarks like Brent and Oman offer more liquidity," he said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com ;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Australia may temporarily allow refiners to blend excess jet fuel into other oil products after local aviation fuel demand plunged by 90% amid the ongoing coronavirus disease 2019 (COVID-19) lockdown measures, the Department of Industry, Science, Energy and Resources said Tuesday in an emailed response to questions.
"The government is currently working with industry on applications to
temporarily vary some aspects of the national fuel standards. The aim ... will be to provide some immediate relief to local refineries by allowing them to blend excess jet fuel into other products, easing their storage burden," it said.
"If required, a converted product will only be sold to industrial facilities
that can handle the modified fuel, such as mine sites," it added.
Domestic and international air travel has been among the industries to bear the brunt of lockdown measures.
Virgin Australia, the nation's second largest airline, announced on April 21 that it had entered into voluntary administration. The airline slashed 90% of its domestic flights and grounded 125 aircrafts on March 25, a day after Prime Minister Scott Morrison announced a ban on overseas travel.
Australia's four refiners have reduced output as federal and state limits on non-essential travel to slow the spread of COVID-19 severely curtail fuel demand.
Melbourne-headquartered Viva Energy plans to shut down a residual catalytic cracking unit (RCUU) and other related facilities at its Geelong refinery in Victoria, as reported by IHS Markit OPIS on Monday.
The other refiners, Mobil Australia, Caltex Australia and BP Australia, have also taken measures to reduce output, as previously reported.
Get an overview of fuel pricing and margin trends in the Australian market with the OPIS Australian Oil Market Price Report.
--Reporting by Trisha Huang, Trisha.Huang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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The uncertainty and unprecedented slide in fuel demand resulting from the coronavirus disease 2019 (COVID-19) has cooled the once red-hot downstream petroleum consolidation, according to some observers.
An industry consultant said most of the deals he is familiar with have been postponed 30-60 days.
"The real issue will be values when things pick up again. Equities are off about 25% and private markets follow but more slowly," he said. "The driver behind all deals is what does a recovery look like. It's not as bad for our industry, but we don't see a V-shaped recovery on the consumer (gasoline) side." Though some states are gradually lifting stay-at-home orders, which should increase fuel demand, he said production "is going to bottle-neck" and demand won't soon return to the pre-pandemic normal. People will still be practicing social distancing to keep the virus at bay, he said.
A recent case in point is Alimentation Couche-Tard Inc., which shelved its widely reported $8.6 billion purchase of Caltex Australia Ltd. In a statement, Couche-Tard confirmed that due diligence for the transaction has been "substantially completed" and Caltex is a "strong strategic fit for Couche-Tard and an important component of its Asia Pacific expansion strategy."
The convenience store giant also said there are "significant opportunities to be realized from combining both businesses," and it remains "highly interested" in the transaction. But because of COVID-19, "the current situation in the world is highly uncertain." Brian Hannasch, president and CEO, said Couche-Tard plans to go forward with the deal when there is "sufficient clarity as to the global outlook."
Steve Griffin, managing partner of Downstream Energy Partners, an advisory firm serving petroleum marketers, said the downstream M&A market is "recalibrating due to the virus," prompting many questions, for example, on how the pandemic will affect transaction multiples. Those multiples had been "high," but marketers wonder if "there will be a retracement," he said.
There also is concern on whether the M&A activity will return to the rapid pace before the virus spread.
"Will the new EBITDA be EBITDAC (earnings before interest, taxes, depreciation, amortization and coronavirus)?" Griffin wondered. "For now, we are left anxious and with bated breath."
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Donna Harris, dharris@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Jet fuel prices in the Middle East are likely to trade in single digits and could even flip negative due to widespread demand destruction, according to market sources.
The cost of jet fuel loaded FOB in the Middle Gulf plummeted to $8.45/bbl ($66.67/metric ton) this Wednesday, OPIS Asia report shows, compared to $82.85/bbl ($653.7/ton) same time last year. OPIS calculates the cost of FOB Middle East Gulf jet fuel as a freight netback from FOB Singapore quotes.
IHS Markit forecasts Middle East Gulf jet fuel will remain in single figures for dollars per barrel during the next couple of weeks, depressed by nosediving Middle East crude prices. Still, Matthew Chew, research and analytics manager at IHS Markit, did not rule out negative jet pricing.
"Daily fluctuations and trading play could cause [jet fuel prices] to drop lower like we have seen for WTI futures earlier this week, which fell into negative territory," Chew said on Friday.
OPIS Asia team pegged May jet fuel cracks in Singapore at negative $2.03/bbl compared to gasoil cracks at $5.37/bbl on Friday.
"I can definitely see Middle East jet fuel prices plummet to negative figures," a trading source told OPIS, as better refining margins are likely to incentivise local refiners to maximise diesel production compared to jet fuel.
A number of Middle Eastern refineries, such as the 537,000 b/d Ruwais refinery and the 466,000 b/d Mina-al-Ahmadi refinery, currently have units undergoing maintenance.
"Refineries have two options - cut runs or pay someone to take the jet away. If these refineries do come back online, they will only produce diesel," the source said. Another source told OPIS that this is already happening in the Middle East.
Middle Eastern refiners typically sell jet fuel to Europe, as the region is a net importer, but the coronavirus disease 2019 (COVID-19) outbreak has decimated European jet fuel demand and local storage is filling up. Meanwhile, soaring demand for floating storage has boosted rates, with freight to transport a 90,000-ton jet fuel cargoes to Europe from the Middle East Gulf to $86/metric tons, compared to $20.3/metric ton same time last year, according to shipbroker data.
Market consultancy JBC Energy noted negative jet prices would only be artificial and driven by soaring freight costs. "That does not mean that actual volumes leaving Middle East refineries will really receive such a price," representative of the JBC Energy Research Centre told OPIS on Thursday.
IHS Markit forecasts global jet fuel demand to decline by 65% to 2.9 million b/d in the second quarter compared to same time last year.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report. Try it free for 21 days
--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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South Korean refinery runs in March fell to a five-month low as the coronavirus disease 2019 (COVID-19) sent domestic fuel consumption tumbling to a near four-year low.
Crude throughput last month fell 4.3% to 2.826 million barrels a day (b/d), the lowest since October 2019, data released on Thursday by the Korea National Oil Corp (KNOC) showed.
Domestic demand for overall petroleum products slid 7.4% to a total of 71.347 million bbls, the smallest since April 2016, according to the KNOC data.
The runs are expected to fall further as fuel demand across the globe faltered on the pandemic and local refiners undertake maintenance works, analysts said.
"The COVID-19 hit consumption and forced refiners to cut runs. The runs would fall further on turnarounds and as demand is unlikely to recover soon," said an industry analyst based in Seoul.
Hyundai Oilbank (HOB) started on April 15 turnarounds at the 360,000 b/d No. 2 crude distillation unit (CDU) and a 53,000 b/d fluid catalytic cracker (FCC) at the Daesan refinery as scheduled, a source with direct knowledge on the matter said. The maintenance was scheduled to complete on May 7.
In mid-March, GS Caltex shut its 155,000 b/d No. 2 CDU and other facilities such as a 90,000 b/d naphtha splitter and an 81,000 b/d catalytic reformer for maintenance, which is set to last until the end of April, as reported earlier.
Refiners worldwide have slashed runs as the COVID-19 pandemic dampened consumption of refined products, especially transportation fuels.
South Korea was not an exception.
Jet fuel consumption shrank to 1.138 million bbls, the lowest on the data going back to 1997. Gasoline and gasoil demand skidded 15.1% and 11.9% on-year to 5.792 million bbls and 12.993 million bbls, respectively.
The refiners have focused more on exports as local demand faltered.
Exports of refined product increased 21.8% to 48.327 million bbls. Overseas sales of jet fuel rose 12.4% to 9.826 million bbls and gasoil shipments rose 32.2% to 18.2 million bbls.
The analyst doubted if exports could stay firm as the COVID-19 has led to severe demand destruction in just about every country as billions of people were told to stay at home to curb the spread of the virus.
"Exports are likely to fall, given lack of demand. Turnarounds will also cut exports," he said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Much of the daily volume in NYMEX products trading revolves around inter-product spreads, and the "spread du jour" today and for many other spring days looks like the buy RBOB/short ULSD play. Even before today's Energy Information Administration report, that spread strategy was attracting fans and it may get a further boost from today's data as well as future EIA reports through May.
The notion of a more-pessimistic outlook for diesel was raised in an OPIS webinar yesterday that featured IHS Refining Expert Debnil Chowdhury and OPIS veteran analyst Tom Kloza. Chowdhury noted that refiners appear to have "gotten an accurate handle" on spring demand and had adjusted gasoline yields accordingly. But he stressed that the worst of diesel demand destruction had yet to arrive in North America, with some additional risk tied to exports.
Kloza added that OPIS demand surveys were no longer suggesting additional volume losses for gasoline, but the same surveys saw attrition for diesel.
Earlier this spring, ULSD futures occasionally commanded a premium of about 40cts/gal to RBOB. A glance at April 22 futures shows those spreads have narrowed substantially. As of Wednesday afternoon, May diesel futures fetched a 15.5ct/gal premium to May RBOB, with the spread narrowing to 14cts/gal in June and spending the rest of the summer at 15.5-17cts/gal.
In the webinar, Kloza noted that because futures markets typically trade 50 or even 60 times the volumes witnessed in wet markets, the futures market can "create its own ecosystem." That ecosystem often drives more volume than outright purchases or sales by funds, speculators or commercial interests.
Margins are dramatically reduced for spread plays, and transactions reflecting spreads can result in much more dramatic moves than would otherwise occur.
EIA data implies that refiners may be producing too much diesel. Production of 15-ppm diesel was 4.63 million b/d last week, or relatively close to maximum levels seen last summer and autumn. Overall distillate production was over 5 million b/d.
Domestic diesel demand was just 3.128 million b/d and it's not unusual for global distillate markets to reach a nadir in May. Two weeks ago, EIA presented the lowest distillate demand number of the 21st century, but odds suggest some May weeks may dip even lower.
A primary risk comes in the diesel export market. Two of the early weeks in April saw diesel demand top 1.5 million b/d with most of the fuel departing for Central and South American locations. Outbreaks of the coronavirus disease 2019 (COVID-19) in the Southern Hemisphere may be more severe as countries south of the equator move into winter and diesel use in countries from Mexico south to Cape Horn is threatened. Exports actually plummeted in the week ending April 17 to just 860,000 b/d, reflecting two fewer cargoes per day leaving Gulf Coast refineries.
Another likely depressant for diesel comes via less long-haul trucking and a nosedive in fuel usage from buses. Plenty of stories are documenting food and medical supplies crisscrossing the country, but commerce in automobiles, furniture, household white goods, etc., has plummeted.
Meanwhile, the fleet of 480,000 U.S. school buses that transport 26 million children daily is for all intents and purposes idle with no prospect of fuel usage into summer and perhaps beyond. The same dour forecast can be made for the 96,000 or so transit buses and the 35,000 motor coaches that move travelers and tourists. Toss in the loss of a substantial portion of diesel used in various segments of the shale business, and you have prospects for total diesel demand (domestic and exports) of less than 3.5 million b/d.
Gasoline demand, on the other hand, could easily rise by 50% or more if COVID-19 cases wane ahead of the last three months of the "driving season."
OPIS volume data suggest that motor fuel demand is running just under 5 million b/d, so a 50% increase would merely take consumption up to 7.5 million b/d.
It's hard to find any instance where U.S. refiners were challenged by a 50% demand increase without repercussions in the distribution system. Current gasoline inventories of 263 million b/d represent about 53 days' supply at 5 million b/d, but that would get sliced to under 34 days' supply if demand picked up to 7.75 million b/d.
All of these assessments may represent a "blue sky" outlook for gasoline and a "gray sky" outlook for diesel. But there are veteran spread traders who believe that a long RBOB/short ULSD strategy for the next 90-100 days may represent one of the better opportunities of 2020.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by OPIS staff;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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China's crude throughput in March fell as the coronavirus disease 2019 (COVID-19) hurt domestic consumption but refinery runs may rebound next month on post-pandemic demand recovery.
Chinese refiners processed 50.04 million mt of crude oil in March, or 11.83 million barrels a day (b/d), down 6.6% from a year earlier, according to data from the National Bureau of Statistics (NBS). The daily processing volume was 2.4% lower than 12.12 million b/d in the January-February period.
The NBS did not disclose the breakdown for January and February.
Crude runs, however, were predicted to increase on-month in April as local demand was recovering, analysts said.
"Refinery runs are expected to increase month-on-month bases with downstream demand showing signs of recovery, although the throughput will still see declines on year-on-year basis," said Sophie Fengli Shi, principal analyst at IHS Markit in Beijing.
China has already eased measures to control the COVID-19. Earlier this month, the government has ended its lockdown of Wuhan, the epicentre of the virus.
Gasoil demand picked up with many enterprises resuming logistical operations and spring ploughing starting in some regions. Falling gasoline prices also prompted more drivers to use their cars.
The government last month also said it will not cut domestic oil product prices further after global crude prices fell below $40/bbl, the floor for the nation's product pricing system, as OPIS reported earlier.
That encouraged local refiners to raise runs, analysts and traders said.
Still, crude throughput in the country may not post annual growth soon due to the steep demand fall already registered, they said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon Jongwoo.Cheon@ihsmarkit.com;
--Editing by Hanwei Wu, Hanwei.Wu@ihsmarkit.com
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One critical element of the gasoline demand destruction is that state revenues collected from fuel taxes were sharply lower in March, and April is shaping up to be much worse.
Lost gasoline tax revenue is just one spoke in a wheel of multiple avenues where state budgets are taking a hard hit over the past six to eight weeks.
Based on 2019 taxable gallons and 2020 OPIS estimated volumes, average state tax losses year on year averaged 17.5% in March with losses in revenue coming in as high as 25.7%. April estimates for lost tax revenue average 45% with multiple states taking in less than half what they did in April 2019.
It's no surprise that California saw the biggest tax hit in March, because it was one of the first states to implement stay-at-home orders to help combat the spread of coronavirus disease 2019 (COVID-19). In March 2019, California collected taxes on about 1.3 billion gal of fuel sold, but OPIS estimates that taxable gallons totaled less than 961 million in March 2020. Overall that adds up to a roughly $180 million loss in tax revenue, and April losses are shaping up to be almost double the lost revenue, with OPIS calculating a 51.4% in fuel tax collections, or $356.87 million.
California can also be a bit different than other states because the state imposes a 2.25% sales tax, and some municipalities have a local sales tax, said James Allison, public affairs and member services manager for the California Fuels and Convenience Alliance.
While each municipality may have a different tax structure, Allison said that on average the figure works out to be about 3.62cts/gal. That revenue from local taxes can be used for road repairs, public health and more, Allison said.
"We likely won't know the tangible impact for localities this has until well after the crisis has passed. Suffice it to say, however, it will almost assuredly hit the urban, populous areas of the state much more heavily than others, simply because they are reliant on sales tax revenue, of which gas stations are a primary contributor," Allison said.
The COVID-19 pandemic has ravaged U.S. fuel demand in April. According to an exclusive OPIS survey of about 15,000 stations throughout the country, March gasoline demand was down 19.1% versus the same month last year, and through the first half of April gasoline demand is down 48.8% versus the same time frame last year.
During March, just three states saw fuel volumes drop by 100 million gal or more: California (332.1 million), Florida (108.8 million) and Texas (233.7 million). In April, OPIS data suggest that 23 states will see fuel volumes fall by more than 100 million gal, with eight seeing demand losses greater than 200 million gal versus levels of April 2019.
Once again, California and Texas are seeing the largest volume losses, of 657 million and 567 million gal, respectively. The gallons lost lead to tax collections being down either side of 50% in those two states, which are the largest in terms of population.
On a percentage basis, though, Michigan appears to be in more dire straits, with fuel sales tax revenue this month projected to be down 58.4%, or $63.1 million, than in April 2019. Michigan is also one of the states in which April volumes are expected to fall roughly 223 million gal year on year.
The tightening of state budgets is not being lost among leadership, with recent local reports indicating that Michigan is considering layoffs of non-essential workers. The Michigan State Budget Office estimates that economic impact from COVID-19 could leave a $1 billion-$3 billion revenue gap for the state during the fiscal year, which runs through the end of September.
The lost tax revenue from fuel sales is just one thing, but if people are not driving many are not likely going to shopping malls and movie theaters. As a result, states are losing out on millions of dollars in sales taxes.
States like Florida that rely on tourism dollars are also getting hit hard.
When attractions like Disney World will reopen is one of the key questions being asked. With many popular attractions temporarily closed, significant sources of revenue are being lost with few hotel rooms and flights being booked and not many rental cars being used.
Adding to the tourism-revenue concerns is increased unemployment, as U.S. claims have jumped by nearly 22 million over the past four weeks.
Florida gasoline sales for April are anticipated to slide from April 2019's 852 million gal-plus to less than 460 million gal.
Ned Bowman, executive director of the Florida Petroleum Marketers Association, sees the state trying to adjust, but is skeptical of a return to normal as far as gasoline demand is concerned.
Bowman notes that some rural areas are doing OK, but even with that he breaks down the math like this: Say Florida sees 250 million gal per week gal consumed. Even if it can get back to of half that, the sales would represent only about one-sixth the typical tax revenue the state would receive. Bowman estimates that would lead to at least a 10%-15% decrease in funds allocated to roads and inspections.
Bowman also worries about the loss of inside store sales and the chances of some independents being unable to make lease payments and permanently shutting their stores.
Convenience stores are in a unique predicament. As oil and refined product markets have collapsed, rack-to-retail margins moved to record heights; though that is still the case with strong margins, lost volumes take away some of the celebratory margins. There is also the other side of the c-store aspect: inside sales. Location can be a key determinant for inside store sales along with offerings, but while fresh data may be a few weeks away, anecdotally at worst inside store sales are off by 25%, sources estimate.
However, there could be some instances in which inside store sales are markedly better, with some stores operating in a region with few retail options. For perspective, 2019 inside store sales were up 4.4% ($251.9 billion), according to recently released figures from the National Association of Convenience Stores.
Ultimately, it is still too early to tell what the damage to state budgets will look like once the economy is back up and running. Even with a piecemeal approach, as states reopen most analysts agree that a wholesale culture change will take place after a period of adjustment.
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--Reporting by Denton Cinquegrana, dcinquegrana@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Indonesian state-run Pertamina plans to carry out turnarounds at some refineries and cut runs as domestic demand tumbled due to the coronavirus disease 2019 (COVID-19).
Pertamina said in a statement on Saturday that maintenance works at the 260,000 barrels a day (b/d) Balikpapan Refinery and 50,000 b/d Sungai Pakning refinery will be conducted earlier with termination at the crude distillation unit (CDU) alternately, though the company did not provide a specific timeframe.
The Plaju refinery with a 118,000 b/d capacity will cut operating ratios, while the 125,000 b/d Balongan refinery, 348,000 b/d Cilacap refinery and 10,000 b/d Kasim refinery will continue to operate normally, according to the statement.
"Pertamina will begin to reduce the refinery's operating capacity in stages according to demand conditions. Technically, the decline will also be adjusted to the refinery processing safety limit," said Pertamina Corporate Communication Vice President Fajriyah Usman.
Last week, Pertamina's chief executive officer Nicke Widyawati said it will reduce runs the Balikpapan refinery this month and may shut the site completely in May, as reported earlier.
Since March 2020, fuel demand in the country declined 35% compared to the average January-February 2020, Pertamina said. Gasoline demand fell 17%, gasoil slumped 8% and aviation fuel dropped by 45%, according to the company.
In major cities, fuel demand suffered decline of above 50% as the government took measures to curb the COVID-19 with consumption in Jakarta and Bandung down almost 60%.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Hanwei Wu, Hanwei.Wu@ihsmarkit.com
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The renowned founder of Singapore oil trading firm Hin Leong Trading (HLT), Lim Oon Kuin, has stepped down as the company's director and managing director, according to a court filing that also suggested he hid $800 million in derivatives trading losses.
The affidavit, dated 17 April and seen by OPIS IHS Markit, was submitted by Lim Oon Kuin himself to support an application to the Singapore high court for a six-month debt moratorium for beleaguered HLT. The resignation was to be effective immediately following the filing of the application. Lim would have "no executive or management function" in the company.
HLT's total liabilities are about $4.05 billion while its assets are valued at $714 million as of April 9, according to the affidavit. HLT, one of Asia's biggest independent oil traders, had sought advisories from lawyers, Rajah and Tann, and consultants PwC Singapore amid a credit freeze by its lenders, OPIS IHS Markit reported last week.
In describing its precarious state of finance in the court filing, Lim said HLT lost about US$800 million in the futures over the years but did not record these losses in its financial statements under his instructions. Margin calls resulting from these positions were recorded as "accounts receivables" and remained as such even after the losses were realized. Lim said he had told the finance department that he "would be responsible if anything went wrong".
HLT had also sold "a substantial part of its inventory and used the proceeds as its general funds" even though the cargoes were bought with inventory financing provided by banks, Lim said.
In inventory financing, the "inventory" in question is typically pledged as collateral to the lender. Sales proceeds from the inventory are used to pay back the loan. To use the proceeds as general funds could leave the lender without collateral to claim in the event of a default.
HLT had also borrowed against bills of lading on transactions that were "executed on paper only". Lim said he gave "general instructions for such transactions to be done but do not recall the precise transactions or the details of such transactions".
HLT is the first known Asian trading company to battle financial troubles amid a precipitous fall in oil prices. Whiting Petroleum in the US had filed for bankruptcy protection earlier this month.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Thomas Cho, Thomas.Cho@ihsmarkit.com;
---Editing by Hanwei Wu, Hanwei.Wu@ihsmarkit.com
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India is turning to the U.S. for additional liquefied petroleum gas (LPG) supplies in the face of reduced output from the Middle East, which has flung open the arbitrage for incremental cargoes to be shipped from the U.S. Gulf Coast to help meet surging domestic demand, market sources said.
A countrywide lockdown that has now been extended to May 3 to curb the spread of the coronavirus disease 2019 (COVID-19) has sent demand for LPG bottles used as household cooking fuel soaring amid a government pledge to hand out free canisters to the poor.
At least two to three cargoes, totaling as much as 135,000 mt, were booked or are on their way to India from the U.S. for May delivery, said the sources, adding that U.S. producers have increased their butane ratio to meet this incremental demand.
India imported 575,130 mt of LPG from the U.S. in 2019, a mere 4% of its total imports, however, it was an increase rose from zero in the past few years, according to IHS Markit's Global Trade Atlas (GTA) data.
Three evenly-split cargoes were loaded onto very large gas carriers (VLGCs) in January from the Enterprise Terminal and one similar parcel was loaded in February, based on IHS Markit's Waterborne LPG report. Each cargo is around 45,000 mt.
Indian importers usually prefer cargoes from the Middle East due to its proximity. It takes more than 30 days for material from the U.S. Gulf to land in the Indian west coast via the Suez Canal versus less than five days from the Arab Gulf.
U.S. suppliers have also had to tweak their LPG increase the butane content as their export cargoes are usually propane rich, according to sources.
It set to ship a total at least 1 million of butane in April compared to 804,339 mt in March, equivalent to a 28% on-month increase, based on the Waterborne data.
A lower U.S. butane price is also acting as a booster for exports, said sources.
The Mont Belvieu TET and non-TET normal butane reached historic lows at 15.6875 cts/gal and 20.0625 cts/gal, respectively, on March 23, and 4-5 cts/gal lower than their respective propane prices, according to IHS Markit OPIS data.
The U.S. to Asia arbitrage has grown recently due to increased demand from Japan and South Korea, the usual key buyers of U.S. materials, and China, which lifted tariffs on U.S. LPG, said sources.
The spot chartering rates for Houston to Chiba route has gained by $21/mt since its a year-low of $75/mt in end-March, based on OPIS record.
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--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Oil tankers hauling jet fuel are diverting to the U.S. away from Europe, as onshore storage tanks fill with product amid collapsing demand, according to shipbroker and IHS Markit Commodities at Sea data.
OPIS is tracking some 300,000 metric tons of jet fuel on five different vessels that were originally chartered from the Middle East Gulf and West Coast of India to sail to Europe. The BW Columbia and BW Rhine, carrying 60,000-tons and 65,000-tons of jet respectively, were both chartered to Europe, but are now signalling for New York discharge, according to satellite tracking data.
BP has chartered a 65,000-ton and a 60,000-ton jet cargo loading from the west coast of India on the UACC Eagle and the STI Expedite, respectively, according to shipbroker reports. The UACC Eagle is now signalling for Port Alucroix on the U.S. Virgin Islands and is due to arrive next Friday, while the STI Expedite is scheduled to arrive at Limetree Bay on May 9. ATC chartered the Red Eagle, which diverted to Port Everglades in early April, shipping 60,000 tons of jet fuel that loaded in the Middle East.
"Some of these vessels were booked...before the crisis escalated," one source said, adding that others may have opted to sail to the U.S. as there was ullage left.
"The market will try to make the most of this contango," said a second source.
"People will...be looking at options to take jet to the U.S. with extended delivery."
The northwest European CIF cargo jet fuel front-month swap was pegged at $31.80/ton below the second month at Wednesday's close. That compares to just an 85cts/ton contango between the front two months in January.
A range of factors is taken into account when calculating the costs of storage, at onshore farms and onboard vessels, but with the structure so wide, floating storage for the prompter months is a viable option, sources told OPIS.
Market sources have indicated that jet fuel storage in northwest Europe and the Mediterranean may be close to capacity. Jet fuel demand in Europe has plummeted amid the coronavirus disease 2019 (COVID-19) pandemic outbreak, with some airlines in Europe grounding their entire fleets.
In comparison, U.S. jet fuel inventories stood at 40.24 million barrels, some 2.13 million barrels lower than same time last year, according to the latest data from the U.S Energy Information Administration.
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--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
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Earlier this spring, prices for ULSD futures rallied to fetch numbers more than 54cts gal over RBOB. The consensus view was that demand destruction was negligible for diesel but at a record-setting pace for motor fuel.
A funny thing has happened more recently, however. Demand destruction for diesel has accelerated while gasoline demand appears to be plateauing at around 48% of April 2019 numbers. And quite a few futures participants have embraced buying RBOB and selling ULSD, confident that the former would outperform the latter.
This week's Energy Information Administration (EIA) report showed just 2.75 million b/d of domestic distillate consumption, representing a drop of 31% and marking the lowest weekly figure in more than 22 years. Large retailers and commercial distributors have noticed an acceleration in diesel demand destruction but believe year-on-year drops of about 15%-20% are common. Losses are more substantial in places like West Texas and North Dakota as cuts in shale exploration and production steepen.
There's a sense that spread trading has accounted for much of the damage in diesel prices in April. Spread plays require much less margin than outright positions in futures, and those 50ct/gal premiums have narrowed to about 18ct/gal more recently. Heavy action in spreads often "creates its own eco-system" in the futures markets and can often dwarf typical buy or sell-side hedging, sources observe.
But like NYMEX RBOB, the price of NYMEX ULSD has disconnected with some of the spot markets across the country. Discounts for the seven cash diesel markets that OPIS tracks for that transportation fuel range from 0.75cts/gal in Group 3 and minus 1.5cts/gal in New York to as much as 14-17cts/gal in California and 21.5cts/gal in Chicago. For the longest stretch, refiners on the coasts of the country were able to get $1/gal or more for ULSD, reflecting a per-barrel price of at least $42/bbl. As of midday Thursday, Great Lakes refiners could get no more than 72.4cts/gal, or a little over $30/bbl.
Put another way, diesel returns subsidized the losses for gasoline in the first quarter of 2020, and those subsidies have faded badly in April.
What worries refiners is history. May often brings the nadir for global demand for distillate. It's a shoulder month without much demand for heating fuel in the Northern or Southern Hemisphere. Most recent U.S. exports have been brisk at nearly 1.6 million b/d, but that may represent the best U.S. processors can do in the entire second quarter.
Disposing of diesel is already a significant problem in some parts of the country. OPIS' Bottom Line report, which tracks discounted barrels of diesel and gasoline, is now dotted with red ink. "Red" denotes markets where the OPIS Rack Low for ULSD is discounted, and recent days have seen plenty of double-digit markdowns.
Western markets see widespread difficulty in "clearing" diesel. Typical postings in California are well above $1/gal, but sharp buyers can find product (ex CCA costs) for about 80cts/gal in Sacramento, Richmond, and San Francisco.
The southeastern U.S. has seen prices tilt sharply lower. Georgia had gallons available in Bainbridge for as little as 85.85cts/gal with 88-89cts/gal common.
But the cheapest diesel is found in the regions that were most disadvantaged by hard-to-clear gluts of gasoline a month ago. Illinois rack prices of 65-66cts/gal were common throughout the state, and Indiana numbers were similar. Michigan had a poor winter for gasoline netbacks, and diesel is now commonly available for just 66-67cts/gal at multiple points. St. Louis saw a 16.98ct/gal price this morning that yielded an outright number of 66.25cts/gal.
And Ohio saw rack prices in Toledo and Cleveland drop below 69cts/gal, as compared to Pennsylvania prices that were mostly in the 90-98ct/gal range.
And Milwaukee continues to be a quizzical local market. Just a week ago, E10 values slipped to about 20cts/gal, representing a poor return for refiners with even the cheapest feedstock. This morning's racks saw Milwaukee diesel fetch just 67.10cts/gal.
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***Monitor rack price changes as they happen, on the web and on your phone.***
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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MEXICO CITY - As the Mexican government expects an imminent rollout of phase three of its strict quarantine measures against the coronavirus disease 2019 (COVID-19), IHS Markit expects Mexican demand could drop as much as 45% year over year (YOY) in April and May.
On Tuesday evening, Mexico's Deputy Health Secretary Hugo Lopez-Gatell said the government projects that regional outbreaks could spread the virus at a national level, generating thousands of infections and putting the country's health system at risk of collapse.
"Phase three is inevitable. The epidemic isn't going to slow down. It is unstoppable," Lopez-Gatell said at a webcast press conference. Previously, the deputy secretary said it is likely that phase three measures will be rolled out by the end of the month.
Lopez-Gatell said as of Tuesday evening, Mexico reported 5,400 confirmed COVID-19 cases and 406 deaths. Based on the number of confirmed cases under its Sentinel Monitoring System, the Mexican government infers there could be 44,000 COVID-19 cases across Mexico.
Phase three will be implemented at a national scale due to the high level of mobility among states. Certain regions, such as Mexico City, Quintana Roo and the Baja California Peninsula, already have critical levels of infections.
"We consider it could be confusing for the population if we had localized declarations," Lopez-Gatell said.
Paulina Gallardo, an IHS Markit downstream analyst for Latin America, told OPIS that the size of the drop in gasoline demand in Mexico and how fast its recovery to pre-COVID-19 levels will depend on how effective the country is at containing the pandemic.
"The determinant factor on any fuel demand projection is how restrictive Mexico's quarantine measures are under phase three," Gallardo said. There is a risk that Mexico could undergo a slower U-shaped recovery, rather than a V-shaped one under stricter social distancing measures seen in countries like Spain, Italy, and China.
It is yet to be seen how restrictive Mexico's federal government quarantine measures will be under phase three and the plan's impact on mobility. However, President Andres Manuel Lopez Obrador said no state of emergency would be declared, nor will he use security forces to ensure people stay in quarantine.
IHS Markit, under its base scenario with a slim U-shaped recovery, expects gasoline demand to begin recovering in September to normal levels with a YOY drop in demand in April and May of around 35%. Under this projection, Mexico's gasoline demand in 2021 could be between 760,000 and 780,000 b/d, slightly under 2019 reported levels.
However, under the worst-case scenario with an extended U-shaped recovery, quarantine measures won't be strictly followed. Therefore, demand could drop YOY by 35%-45% from April to July with fuel demand recovering to normal levels later in 2021 due to a major GDP contraction, Gallardo said.
"If the economic conditions worsen, fuel demand in 2021 could be 40,000 to 50,000 b/d lower than the average for 2019," she said.
Projecting how much diesel demand will shrink during the peak of the COVID-19 pandemic in Mexico is more complicated, Gallardo said. The worst hit on diesel demand could be seen in May, after stock inventories deplete in April amid a shutdown of manufacturing plants and other factories.
The drop in diesel demand YOY for 2020 could be 10% compared with the previous year, Gallardo said. However, other sectors, such as the agricultural industry, could provide support for diesel demand.
"How rapidly diesel demand recovers this year will depend on how fast manufacturing activity picks up after the COVID-19 pandemic is constrained," she added.
Mexico Mobility Trend Remain High
In Spain-one of the nations with the strictest quarantine currently in place - the volume of gasoline distributed during the first week of April fell 82%, 68% for diesel and 92% for jet fuel, according to a report from Spain's largest midstream operator, Compañia Logistica de Hidrocarburos (CLH).
Google mobility data shows that the number of people going to retail and recreation sites fell 94% on the week ended April 5 versus January, 89% for transit stations, 77% for grocery and pharmacies, and 68% for workplaces.
In comparison, the number of people going to retail and recreation sites in Mexico fell 62%, 50% for transit stations, 27% for workplaces, and 19% for groceries and pharmacies, Google mobility data shows. This despite the government suspending all non-essential economic activity on March 30 and urging all people to stay home.
Data collected by OPIS from fuel retail networks shows gasoline sales in the U.S. dropped 48% during the first week of April. Google mobility data shows that week the number of people going to retail and recreation sites fell 49% across the U.S., 54% for transit stations, 40% for workplaces and 20% for groceries and pharmacies.
Lopez-Gatell said Tuesday that mobility in Mexico City had dropped 70% against normal levels as a result of social distancing measures. However, the deputy secretary said there is no reliable data for from local and state governments for other parts of the country.
During the last week of March, gasoline demand dropped 15.7% YOY, down to 701,000 b/d compared with 811,000 b/d a year ago. In the case of diesel, during the last week of March, diesel demand fell 7.8% YOY to 380,000 b/d.
Mexico's largest fuel retail association ONEXPO told OPIS on Monday fuel demand fell 40% YOY during the first week of April, according to reports from its members.
Market sources told OPIS that fuel sales have fallen up to 40%-60% in metropolitan cities and at retail stations in areas with high acquisitive power. Meanwhile, demand in many rural stations and smaller urban areas remains close to normal.
The most affected states have been Baja California Sur with 20 COVID-19 cases per 100,000 people, Mexico City with 17 casesper 100,000, Quintana Roo with 14 cases per 100,000, Baja California with 11 cases per 100,000, Sinaloa with eight cases per 100,000, Tabasco with seven cases per 100,000, the deputy secretary said.
However, experts have questioned the Lopez Obrador administration COVID-19 picture. The Investigative Science Coordinating Council at Mexico's largest university, UNAM, reported on Monday that it is likely the government could be underreporting COVID-19 cases and logging them as Acute Respiratory Infections (ARI).
The council said the number of ARI cases reported in Mexico has grown.
According to the council, the number of ARI cases have increased by over 150,000 over the average trendline for the last five years.
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--Reporting by Daniel Rodriguez, drodriguez@opisnet.com;
--Editing by Steve Cronin, scroning@opisnet.com
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Indian importers made a rare move to book very large gas carriers (VLGCs) as floating storage in an attempt to cope with massive spot purchases after a surge in domestic cooking gas demand in the wake of a government lockdown to control coronavirus disease 2019 (COVID-19), said market sources.
On the back of Prime Minister Narendra Modi's announcement of a 21-day countrywide lockdown on March 25 that has now been extended to May 3, the government also said that it would provide free liquefied petroleum gas (LPG) to the poor, which sent demand soaring and triggered a slew of buy tenders.
As these buy orders, which were first made 2-3 weeks ago, begin to arrive at the Indian ports and bottleneck emerged as suppliers struggled to break bulk and transport the LPG to bottling plants for final sale to households, they said.
Consequently, at least 2-3 VLGCs were chartered so far as floaters with onshore tanks filled to the brim, said trading sources, adding that lockdown measures, which make worker movements difficult have worsened the supply chain logistics that's already stretched by India's limited LPG storage capacity.
India has an estimated 1 million mt of LPG storage space, which is equivalent to around 22 VLGCs, based on IHS Markit data.
Three state-run refiners have purchased more than 500,000 mt of LPG through tenders issued for delivery from April to early June, said sources.
The country is still seeking more spot cargoes and building up inventories amid the extended lockdown, they said.
It costs around $47,000/day to use a VLGC as a floating storage, according to market sources.
The government said that it will provide free LPG cylinders for three months from April to June to around 80 million families under the PMUY scheme along with other measures in a $22.5 billion stimulus package.
Around 12.6 million LPG cylinders of 14.2 kg, equivalent to 178,920 mt, have already been booked under the Pradhan Mantri Ujjwala (PMUY) scheme this month, according to a local media report.
Indian importers had previously added a force majeure clause associated with COVID-19 to its spot tender that led to higher premiums to cover the risks for sellers, traders said.
Premiums of $30s/mt and $50s/mt were placed to the May CP for a 45,000 mt evenly-split cargo for May delivery to the western and eastern shores, respectively, according to the sources.
As a comparison, recent cargoes sold into further away south and east China for May delivery were heard at premiums of around $40s/mt to the May CP.
No major delays have emerged so far in terms of discharging cargoes in Indian ports, according to a shipping source.
Real-time LPG pricing helps you see how global markets fit together with the OPIS Global LPG Ticker.
Now you can track live the arbitrage relationships between key European and Asian spot LPG markets and the Mont Belvieu, TX, hub where OPIS holds the official industry pricing benchmark. Start my free trial
--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Several U.S. companies, including ExxonMobil, attempted earlier this month to insert clauses in their contracts that would negate the possibility of sales prices below zero.
The effort came against the backdrop of some U.S. spot markets trading in the 20s for various blendstocks, with many formulae deals on the books at large discounts to NYMEX references. Last week, OPIS confirmed rack prices at less than 10cts/gal, and there were worries that spot transactions might descend to where a discount of 40cts/gal to futures might result in a negative price. The clauses for the deals were reportedly invoked for spot deals on the Colonial Pipeline tied to front-month NYMEX products contracts.
What's not known is whether any buyers agreed to the terms. At least one large commodity trading house saw its legal experts reject the terms, noting that "negative pricing" has occurred in recent years in natural gas and electricity.
When reached for comment, ExxonMobil declined, citing its policy of not commenting on commercial matters.
OPIS dealt with negative numbers for Edmonton propane in the middle of the last decade, in one of the most colossal collapses in any commodity in U.S. history.
Propane prices soared to over $4/gal in the Polar Vortex winter of 2013-2014, but by late spring 2015, holders of Edmonton propane had to pay customers to take barrels away.
Sources say that CME has advised clients of its ability to handle negative prices, should another wave of price weakness sweep through petroleum or energy futures.
Negative numbers for crude oil were chronicled in 2016, but crude oil postings work nothing like spot transactions. Instead, buyers declare what they are willing to pay for various grades of crude oil. That year saw Flint Hills Refining post a negative number for some low-grade Rocky Mountain crude oil blends. It is not known whether crude suppliers ever acquiesced and paid the company to take away the crude.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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An accord by a group of producers, known as OPEC+, to reduce global oil output by record amounts for May and June will help stabilize the market but is not far reaching enough to rally prices due to the vast and still unknown scale of demand destruction wreaked by the coronavirus disease 2019 (COVID-19).
The well-telegraphed meeting, which led to sharp price gains last week when word first emerged of a possible reconvening of talks among producers including the two biggest protagonists Saudi Arabia and Russia with the United States providing both the carrot and stick towards a deal, has already been discounted by the market, industry sources said.
"Without this deal, the global industry would have run out of storage for the flood of excess oil in a few weeks and prices would have crashed, which would have also really hit financial markets," said IHS Markit vice chairman Daniel Yergin. "This restrains the build-up of inventories, which will reduce the pressure on prices when normality returns -- whenever that is."
This historical cut, paired with the expected declines and shut-ins likely to occur in the next few months in the United States, Canada and some other countries, promise to remove up to 14 million b/d in May and June, according to Roger Diwan, vice president, financial services at IHS Markit.
"This is a critically-needed relief in the face of declines in crude demand estimated at around 20 million Mb/d," said Diwan. "Stepping away from a destructive price war, the return to market management by Saudi Arabia and Russia and backed by the United States and a very involved President Trump, marks a physical and psychological inflection point for the oil market."
ICE Brent futures initially fell following news of the agreement but rebounded later in the day. At 9 a.m. ET, June Brent futures remained down by 25-30cts and trading at $31.21/bbl. May WTI futures were holding small gains of about a dime at $22.84/bbl. The front-month Brent futures jumped almost 53% from a low of $22.71/bbl on March 31, prior to news of a possible deal, to close at a high of $34.65 on April 3, the data show.
"The market is quite disappointed. Brent came off a bit this morning, the 9.7 million b/d output cut is not enough to offset demand loss. It will only try to delay tank top situation," said one Singapore-based trading source, adding that Saudi Arabia pumped a lot this month and these cargoes will need to go into storage first before a clearer picture of market fundamentals emerges.
"This is a welcome step, but in 2Q the cut is a bit low, where we are forecasting demand reduction of 20 million b/d," said Premasish Das, IHS Markit downstream research and analysis director in Singapore. "A lot depends on the big unknown, 'how the demand recovery takes place' and also how the stakeholders of this production cut comply."
OPEC+ agreed on Sunday to reduce output by 9.7 million b/d for May and OPEC+ June, after four days of talks in the face of pressure from U.S. President Donald Trump. The cut is more than four times larger than the previous record set in 2008.
According to the agreement, producers will slowly ease up the reduction after June but will maintain lower productions until April 2022.
Non-members Brazil, Canada, Norway and the U.S. would contribute 3.7 million b/d, according to media reports, while Gulf OPEC members will make bigger cuts given their bumper output in April.
Another facet of the agreement was that members of the International Energy Agency (IEA) and other major consumers would add 3 million b/d of oil to their strategic stockpile in the coming months. This, as seen in previous IEA commitments, is a bureaucratic process that will take time to materialize.
Trading sources said how the physical oil market reacts to the output cuts will be the ultimate judge of the success of the OPEC+ initiative.
"If the cuts are large enough to reduce the contango to the extent that storage is no longer viable then the freight market will come down for sure," said one ship broker, which he added also translates to reduced pressure on the oil market.
A narrower contango will bring more balance to the market, and for that to happen demand must also pick up, they said.
In the longer term, one fear among participants is that when recovery is entrenched, there will be a temptation for producers to be less compliant with their output cut commitments and prematurely damage the accord.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Sok Peng Chua, SokPeng.Chua@ihsmarkit.com
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German carrier Lufthansa is downsizing its airplane fleet amid expectations that airline traffic recovery could take years, it said in a press release on Tuesday.
Lufthansa's executive board believes that global travel restrictions could be lifted in months, but it could take years for worldwide demand for air travel to return to pre-crisis levels.
In response, Lufthansa and subsidiaries Lufthansa Cityline and Eurowings will decommission 37 Airbus airplanes and five Boeing airplanes, reducing capacity in its Munich and Frankfurt hubs.
The aviation sector is one of the hardest hit by the coronavirus 2019 disease (COVID-19) pandemic, which has seen countries across the globe impose domestic and international travel restrictions.
Data from travel analytics company ForwardKeys shows that global international airline seat capacity for the first week of April declined by more than 77% to 10 million seats from 44.2 million the same time a year ago.
"Governments have closed entire countries. In response to Covid-19, the airline industry has cut services to the bone. It is likely that when we get across to the other side of the pandemic, things won't return to the vibrant market conditions we had at the start of the year," Olivier Ponti, ForwardKeys vice president, insights, said in a statement last week.
However, Lufthansa recovery forecast is markedly more pessimistic compared with IHS Markit's outlook.
Eleanor Budds, associate director at the parent company of OPIS, believes that aviation demand will return to pre-crisis levels in spring-summer 2021.
"After international travel resumes, we expect a lingering downward effect from fear of traveling, lower business travel, potential border entry restrictions, and of course the economic fallout from job losses. Upside will have to come from airline and travel operators offering low prices and flexibility," Budds added.
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--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Paddy Gourlay, patrick.gourlay@ihsmarkit.com
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The U.S. Energy Information Administration's first report of supply and demand figures across all products and regions documents how the coronavirus disease 2019 (COVID-19) has impacted jet fuel supply, production, and demand.
The numbers confirm what IHS Markit, OPIS' parent company, first forecast in March to its clients: that jet fuel demand in April would be 606.7 million b/d compared to 1.75 million b/d in April 2019. May volumes, IHS Markit calculates, will be 767.7 million b/d versus 1.781 million b/d last May, with June 753.4 million b/d compared to 1.799 million b/d June 2019.
Debnil Chowdhury, executive director at IHS Markit, revealed these numbers in an OPIS webinar conducted in March. Get the recording here.
Some believe that the demand destruction for jet fuel may linger into the summer. Airline executives believe it will take years for the industry to recover from the devastating impact for U.S. and global aviation.
EIA reports jet fuel deliveries for the week dipping to 755,000 b/d, which is almost 1 million b/d less than what was reported three weeks ago. Each of the past three weeks have seen declines, but this week's report is the sharpest yet, with weekly deliveries plunging 580,000 b/d from those of the prior week.
IHS Markit also calculates that jet fuel refinery yields have dropped to just 6% nationally -- about as low as they can go, sources tell OPIS. The latest EIA production numbers point to producers lopping 257,000 b/d out of weekly jet output to 872,000 b/d.
Production was cut across all regions: Gulf Coast output, where almost half of the country's fuel is produced, fell to 449,000 b/d -- far off its 1 million b/d rates earlier in the year and 2019. West Coast output toppled to 224,000 b/d, more than half of what the region customarily produces. East Coast production is now 29,000 b/d compared to levels that just a few weeks back topped 100,000 b/d. Midwest output sank to 155,000 b/d, off its 300,000-b/d mark at the end of 2019.
Production and demand numbers are lows not seen in decades.
Inventories of jet fuel rose despite the run cuts as fuel deliveries are crawling. National stocks are 38.9 million bbl compared to 38.3 million a week ago. Most of that gain came in the West and can be attributed to imports that over the last two weeks have averaged 175,000 b/d.
Exports of jet fuel remain strong and are helping to siphon off some surplus barrels.
The run cuts and talk of a possible deal to end the price war between Saudi Arabia and Russia have pushed jet prices higher over the past week, but market values are down just over a penny today, with Gulf Coast barrels priced just over 71cts/gal and Los Angeles 61cts/gal.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Ben Brockwell, bbrockwell@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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The Asia naphtha crack, or refining margin, to Brent crude fell into negative territory this month on the back of weakness in the gasoline market just as a surge in arbitrage cargoes from Europe and the U.S. for May arrival exert more pressure.
The Japan open-specification naphtha (OSN) crack to Brent fell to minus $60.125/mt on April 7, the lowest on IHS Markit OPIS records going back to July 2014. The crack to Brent has been negative for five straight sessions since the start of the month, the longest stretch since June last year with six sessions.
In addition, the OSN first cycle/third cycle contango widened to $7.00/mt on April 7. It was the widest since a similar $7.00/mt contango in September 2016, suggesting weak supply/demand conditions for the second half May cycle.
OSN cracks to Brent this week were weighed by concerns over gasoline demand in Latin America amid the spread of the coronavirus disease 2019 (COVID-19), said a procurement official for a Japanese chemical producer.
Such concerns come in the face of deterioration in gasoline demand in Europe and the U.S. amid lockdowns and efforts to curb the spread of COVID-19. The U.S. west coast and Latin America are export markets for East Asian refiners.
Since gasoline demand has tumbled, naphtha is not going into the gasoline blending pool, said a Singapore-based market source, adding that naphtha barrels were being pushed to Asia for petrochemical use.
"For arbitrage cargoes, May-arrival is said to be 2.5 million mt," the source said, adding that typically 1.7-1.8 million mt per month is shipped.
In addition to loadings from Black Sea ports, Algeria and USGC, recent shipping fixtures show naphtha cargoes from unusual points such as Spanish ports, bound for Japan.
The Kamome Victoria is heading to Japan after loading 60,000 mt from Huelva on April 3, according to fixture lists. The vessel was chartered by Spanish refiner Cepsa at a cost of $2.9 million. IHS Markit's ship-tracking service, Market Intelligence Network (MINT), shows that the tanker left Huelva terminal on April 7 and is now headed toward Port Said in Egypt.
The Torm Signe is also headed to Japan after loading 60,000 mt from Cartagena in late March or early April, fixtures showed. The vessel was chartered by Repsol at a cost of $3 million. MINT shows that the tanker left the Spanish port on April 4 and arrived at the Spanish port of Algeciras on April 7, possibly to pick up top cargoes. There was no indication of its next destination.
Another recent fixture showed a Petrobras chartered vessel BW Yangtze possibly heading to Asia after loading 60,000 mt from Suape port in Brazil on April 2.
The fixture showed that the vessel might make a transatlantic voyage, or head to Singapore or Japan. MINT shows the tanker left Suape on April 3 and is now anchored off Salvador. There was no indication of its next destination.
Cargoes due to be moved from USGC to Asia include 38,000 mt on April 10 on the Carina, chartered by Valero at a cost of $1.25 million, according to fixtures.
The tanker is now moored at Houston port, according to MINT. There was no indication of its next destination.
The cost of 40 N+A naphtha in USGC was at around $163/mt as of April 7, while paraffinic naphtha was about $136/mt, while in Asia, open-specification naphtha for H2 May closed at $193/mt, according to IHS Markit OPIS data.
The higher price in Asia meant that surplus cargoes from almost everywhere are looking towards East Asia in the hope of securing a home, market sources said.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Masayuki Kitano masayuki.kitano@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Oil tanks at the 270,000-b/d Fawley refinery are about to be filled, forcing operator ExxonMobil to use vessels for storage purposes, OPIS has been told.
Sources say that three tankers have been chartered by ExxonMobil to store oil products close to the U.K.'s largest refinery, which is located on the southern English coast.
Sources told OPIS two weeks ago that the U.K. government insisted to the super major that it must keep the refinery running "at all costs" during the COVID-19 pandemic, even as refining margins for products such as gasoline entered double-digit negative territory.
The British government is holding regular conference calls with the refinery's manager in order to receive updates about the plant's status, sources say.
OPIS understands that runs at the refinery have been cut, with one of three pipestill units and one of two powerformer units being taken offline.
Like other refineries, Fawley is attempting to maximise diesel production as it remains the most profitable part of the barrel, say sources.
OPIS assessed the northwest European diesel refining crack at $8.74/bbl on Friday. By contrast, the jet crack was assessed at minus $1.86/bbl and the Eurobob gasoline crack was pegged at minus $9.54/bbl.
Diesel represents 29% of the refinery's output, while gasoline, jet and petrochemical feedstocks make up 28%, 11% and 9% of output.
Fawley is a critical part of the U.K.'s energy infrastructure because of its links to the nation's largest cities and airports.
Eighty-five per cent of the refinery's output is pumped through underground pipelines as far away as London, Birmingham and Bristol. Pipelines connect the refinery to Heathrow and Gatwick airports.
OPIS has previously reported that two other British refineries with turnarounds scheduled to begin in April will also continue to operate and supply fuels during the pandemic.
Heavy maintenance work at the Petroineos-operated 210,000-b/d Grangemouth refinery has been postponed, while sources say that the April-June turnaround scheduled for the Phillips 66-operated 205,000-b/d Immingham refinery has been pushed back to September.
Spokespeople for ExxonMobil, Phillips 66 and Ineos did not respond to requests for comment.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--editing by Paddy Gourlay, patrick.gourlay@ihsmakit.com
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Asian petrochemical manufacturers plan to crack less liquefied petroleum gas (LPG) in May for a second straight month, but this is unlikely to support naphtha consumption much with the coronavirus disease 2019 (COVID-19) denting downstream demand.
LPG usage for petrochemical production in May is set to fall 6.8% on-month to 449,000 mt, according to an IHS Markit OPIS completed on April 7. This month, gas cracking volume is to decline 7.7% to a revised 482,000 mt from 522,000 mt in March, according to the poll.
LPG prices rose on demand from India where a nationwide lockdown boosted demand for the cooking fuel. The CFR Japan propane price on April 5 rose to $287.500/mt, the highest since March 10, IHS Markit OPIS record showed.
As a result, LPG cracking became uneconomical with the propane/naphtha ratio assessed at 142.9%. The ratio compares the first physical trading cycle for naphtha, with the second cycle for the CFR Japan price of 23,000 mt propane.
Petrochemical producers typically find it more attractive to crack naphtha instead of LPG when the ratio rises above 90%. But that's not the case now as the COVID-19 hit the global economy and consumption, analysts and traders said.
"In theory, lower LPG cracking volume may support naphtha consumption, but overall petrochemical demand is too weak to see solid naphtha demand," said Matthew Chew, principal researcher at IHS Markit in Singapore.
Naphtha prices tumbled on poor gasoline and petrochemical demand with the CFR Japan naphtha falling on April 1 to $165.750/mt, the lowest on the IHS Markit OPIS data going back to July 2014.
That helped cut ethylene production costs and improve margins.
The cash cost of steam cracking in Northeast Asia using naphtha was estimated at $91/mt as of March 26, generating a margin of $434/mt, according to the IHS Markit Asia Light Olefins Weekly report published on April 3.
The cost was $582/mt as of March 5 and the margin was $82/mt.
Asian petrochemical producers, however, were reluctant to process more naphtha given the demand crash with some already cutting cracker runs.
"Cracking margins are good in numbers, but we cannot raise runs due to the slowing economy," said a feedstock procurement manager at a petrochemical producer in Northeast Asia, which has been operating its cracker at 90% since January.
"We may cut runs further once downstream demand deteriorates more," said the manager, adding the company did not slash the ratio below 90% even in during the 2008-09 financial crisis.
Ethylene demand in Asia stayed weak on sluggish derivatives consumption, limited exports to India and pessimistic economic outlook, while supply increased on both regional crackers and deep-sea cargoes from Europe, IHS Markit said in the report.
Propylene demand suffered similar issues and supply rose on higher output from fluid catalytic cracking (FCC) units amid rising refinery run rates in Shandong and increased supply from on-purpose production units, according to the report.
The Asian Manufacturing PMI, compiled by IHS Markit, rebounded to 48.3 in March from February's 44.4, the lowest since March 2009. But the index stood still below the 50 threshold, indicating the economy was not out of woods yet.
IHS Markit has revised the forecast for China's GDP growth rate several times since the COVID-19 outbreak, from 5.8% at the start of the year to 4.3% and then to 2.0% as of March 26, according to an April 3 Asia Light Olefins report.
Global GDP is also expected to decelerate at 2.8%.
Methodology: IHS Markit OPIS collects Asian petrochemical companies' plans for the current month and the next month, as well as actual cracking volume in the previous month. IHS Markit OPIS checks if any manufacturers revise their plans for the current month and if any manufacturers crack more or less than initial plans in the previous month. IHS Markit OPIS contacts feedstock procurement officers of each companies for the survey by phone, email or messengers in the last week of previous month or the first week of the current month. IHS Markit OPIS surveys 16-20 companies a month.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report. Get your free trial here
--Reporting by Jongwoo Cheon Jongwoo.Cheon@ihsmarkit.com,Masayuki Kitano Masayuki.Kitano@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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"Flattening the curve" is now the top-of-mind goal for residents of the U.S. and more than 175 other countries. The phrase reflects hopes that the case confirmations and death totals related to coronavirus disease 2019 (COVID-19) stop what has been a relentless spring rise on the charts. Some signs seem to suggest a slowdown in the ascent, although government authorities warn that it is premature to suggest a flat line or imminent descent.
But there are some signs that the graphs showing U.S. gasoline demand in a steep rocky descent may soon hint of a flattening in unprecedented demand destruction. Surveys of large chain retailers across the Lower 48 states imply that this weekend's motor fuel sales were no worse than the previous weekend.
That's a small victory, but for the moment, the supply chain will accept it unconditionally.
Initial data for the weekend suggests that gasoline demand for the period ending April 4 or April 5 was generally consistent with what was witnessed in the last week of March. Multistate marketers tell OPIS that gasoline sales across the continental U.S. was off by 45%-49% from the same period last year.
Teams responsible for projecting April volumes are content with predictions of sales sliced in half.
Individual state data find some drastic "lumpiness."
The state with the most compelling demand destruction may be Michigan. Multiple surveys of traditional stations there have yielded year-on-year sales drops of nearly 60%. Weather may be a wildcard in the stark comparisons, since adjoining states like Indiana and Ohio find demand destruction closer to 40%. All of these states have retail gas that is priced at least $1/gal cheaper than last year, but ironically, Michigan's $1.23/gal discount the same time last year reflects the largest gap in all 50 states. Notwithstanding the largest price break to 2020, Michigan residents appear to be driving much less.
Other clear sore spots are California (down about 47%), Colorado (down about 50%-52%), Illinois (down about 46%), Maryland (off about 57%), Nevada (down about 54%) and Vermont (softer by 50%).
As of this morning, there were still nine U.S. states that did not mandate stay-at-home restrictions. OPIS is still collecting date on chains in some of the states, but fewer restrictions don't necessarily translate into more demand. Data for Oklahoma, for example, implies demand destruction in the high 40% area, pretty consistent with the 41 states that have encumbered travel.
Iowa, on the other hand, generally stands out with some of the most nominal drops in gasoline consumption, with drops in the 27%-28% neighborhood.
Brian Norris, executive director of retail data at OPIS, noted that "OPIS Demand data for the week ending March 28 saw U.S. same-store gasoline sales off by about 47%, so if preliminary data holds true for the week ending April 4 and the numbers look similar, it could potentially signal at least a temporary bottom for national motor fuel demand."
Norris added fuel retailers are anxiously looking for a sign that demand destruction is plateauing, so the full dataset in next Monday's OPIS Demand report will be "critical."
OPIS DemandPro, a web-based tool, looks at actual retail throughputs for the country and for each region and several states. The last full report, measuring demand through March 28, indicated demand at the 4.861 million-b/d level.
EIA Data Can't Help Refiners Gauge Real Demand
The Energy Information Administration has never been a reliable source for measuring domestic gasoline consumption. That's no fault of the EIA, but the surveys managed by its staff simply measure movement of gasoline from primary (reportable) to non-reportable storage. That storage might be the several hundred thousand retail tanks across the country, as well as small bulk plants operated by jobbers.
But that demand construct may be severely altered by the unprecedented premium the market affords large companies with storage tanks and cash or credit. The difference between the May futures price and the August quote at presstime was more than 15cts/gal. There was every incentive for companies to buy near term gasoline and store it for sale in August. No one can quite recall when this "carry trade" or contango play for gasoline has ever been more prosperous.
But buying gasoline for a storage "carry play" is not the same as sales earmarked for immediate sales to consumers.
EIA measured gasoline demand last week (with its traditional methodology) at 6.6 million b/d, a drop of 2.471 million b/d from the same week in 2019. The numbers are likely to show another historically poignant slide this week, perhaps moving below 6 million b/d.
However, the real number for gasoline moving from stations to vehicle tanks is probably much lower than what EIA will release. April gasoline demand averaged 9.356 million b/d last year, and that followed a 9.2 million-b/d fourth month in 2018 and 9.3 million b/d in 2017.
A slide of 47% from last year pushes the implied retail demand number below 5 million b/d, to 4.958 million b/d, or in a statistical dead heat with previous OPIS DemandPro numbers.
Some refiners are planning for sub-5-million-b/d domestic demand through April 30 and perhaps into early May. The forecasts are highly dependent on the flattening of coronavirus curves, not just in the U.S., but in export markets such as Central and South America that can provide an offshore home for about 700,000 b/d of gasoline.
If you are wondering when the U.S. last saw a lower monthly number for gasoline, you need look all the way back to March 1968.
That year is often cited as one of the most tumultuous years in American history. March that year saw the announcement that Alaskan oil was in Prudhoe Bay, discovered by Atlantic Richfield and Humble Oil (now ExxonMobil). At the tail end of March, President Lyndon Johnson announced that he would not run for reelection and November brought the presidency of Richard M. Nixon. As striking as 1968 may have been, however, history may show that it pales compared with the events of 2020.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers. Request a demo
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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ExxonMobil's Fawley refinery FAST project, the largest upgrade to a British refinery in decades, will be subject to a company review scheduled for the end of the third quarter, sources have told OPIS.
The company told investors last month that it is pausing to review its rate of expenditure at the $1.5bn Fawley Strategy (FAST) project, which will boost diesel output at the 270,000-b/d refinery by 38,000-b/d, or 45%.
"They are going to review it in about six months' time," a source said with respect to ExxonMobil. "(Constructing) the new plants won't go ahead until (at least) 2021," said the source, who added that the FAST project could not realistically be finished by the end of 2021, the original target date for completion.
OPIS sources say that work has been curtailed at the main site where construction was scheduled to begin in the first half of this year, but upgrades at existing units are going ahead.
"They paused the main bit -- the building of the (hydrotreater and hydrogen plant) -- but they are going to continue with what they have started, which is the extension to the resid plant and (installing) HD7, which takes wax out.
Those two bits of the project are going to go ahead," said the source.
The resid hydrotreater converts heavy oil products such as fuel oil into lighter, more profitable products.
Sources told OPIS that some workers who had previously been offered work potentially running until October were no longer required at the site.
"The groundworks that have started for block 36B - which is where a new plant is going to be built - the contractors who were doing that were told a few weeks ago to cap the foundations off and demobilise and get off the site," said a source.
Asked whether a lot of contracts had been cancelled, a source replied: "Paused is the word, not cancelled. The job will go ahead one day. Nobody knows for sure when yet."
Asked to confirm that a review of FAST is scheduled six months from now, a spokesman for ExxonMobil said: "To optimise the investment and ensure that it delivers the best possible value, we are reviewing the rate of expenditure on the FAST project through 2020. We remain committed to enhancing the long-term competitiveness of the Fawley refinery."
Major parts of the project have already been constructed, OPIS has previously reported.
OPIS revealed in September that a process column was already under construction in India after being commissioned by Fluor, FAST's EPC contractor, even though planning permission for FAST had not yet been obtained from British local government authorities. That permission was subsequently granted by New Forest District Council.
Shortly before the Christmas break, sources told OPIS that the process column was scheduled to arrive at a nearby port around Boxing Day.
OPIS first revealed that ExxonMobil planned to extend the Fawley plant, Britain's largest refinery, in October 2017. Other media outlets reported the plan 11 months later, when the refinery's manager was interviewed in the Financial Times.
The 270,000-b/d refinery has cut runs in recent weeks by at least 70,000 b/d, sources say, coinciding with a crash in refining margins courtesy of the COVID-19 coronavirus outbreak.
FAST is not the only major project planned by a U.K. refiner to have the timing of its construction work thrown into doubt.
OPIS has learned that construction of a new 350-million pound combined heat and power plant at the Grangemouth refinery complex in Scotland has also been postponed amid uncertainty about the medium-term effect of the global pandemic.
The work was due to begin in the fourth quarter of this year, OPIS sources say.
No new start-date has been proposed by Ineos, say sources.
Spokespeople for Ineos have not replied to inquiries to confirm the story.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Paddy Gourlay, pgourlay@opisnet.com and Rachel Stroud-Goodrich, rstroud-goodrich@opisnet.com
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South Korea's crude imports in March fell to a five-month low, preliminary government data showed, as refiners reduced runs in the face of eroding local demand due to the coronavirus disease 2019 (COVID-19).
Crude purchases in March fell 5.2% on-year to 82.5 million bbls, according to the Ministry of Trade, Industry and Energy data. That would be the smallest since October 2019 when the country bought 82.3 million bbls, data from the Korea National Oil Corp (KNOC) showed.
Crude imports in the coming months are likely to fall further as refinery maintenance works and sluggish demand lead to bigger throughout reductions, an industry analyst based in Seoul said.
"It is inevitable to see declining imports, given the COVID-19 impact on demand and scheduled turnarounds," said the analyst.
In mid-March, GS Caltex shut its No. 2 155,000 barrels a day (b/d) crude distillation unit (CDU) and other facilities such as a 90,000 b/d naphtha splitter and an 81,000 b/d catalytic reformer for maintenance, which was set to last until the end of April, according to industry sources.
Hyundai Oilbank (HOB) plans to conduct turnarounds at the No. 2 360,000 b/d CDU a 53,000 b/d fluid catalytic cracker (FCC) at the Daesan refinery from April 15 to May 7, as reported earlier.
SK Energy is also scheduled to shut the No. 5 260,000 b/d CDU at its Ulsan complex in late May to late June.
Refiners have already lowered runs as domestic consumption of refined products, especially transportation fuels fell sharply. For example, SK Energy slashed runs at its 840,000 barrels a day (b/d) Ulsan complex by up to 15% in March, as reported earlier.
They also focused more on overseas sales.
Oil product exports in the first 25 days of March rose 33.8% in terms of volume and petrochemical shipments grew 17.5%, although overseas sales for the whole month in terms of value fell 5.9% and 9%, respectively, in line with the price crash seen across the energy complex, data from the ministry showed.
Refiners had to sell products at bargain prices to overseas markets as they could not cut runs too much despite poor local demand, the analyst said.
"Exports may not be able to sustain such rises as overseas demand is also weakening and runs will fall on turnarounds," he added.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Whiting Petroleum Corp. on Wednesday announced it was seeking Chapter 11 bankruptcy protection, making it the first major U.S. shale producer to become a casualty in the ongoing price war between Russia and Saudi Arabia that has seen a historic drop in energy prices.
In its announcement, the company said it has more than $585 million of cash on its balance sheet and plans to "continue to operate its business in the normal course without material disruption to its vendors, partners or employees."
Whiting also said it expects to have the liquidity it needs to meet its obligations during the restructuring without the need for additional financing.
The company said the decision to seek bankruptcy protection was due to market conditions that have seen energy prices plummet in recent weeks due to the price war and efforts to contain the coronavirus disease 2019 (COVID-19). On Tuesday, the NYMEX futures complex marked the end of its worst quarterly performance in history. The first quarter of the year saw the contract for U.S. benchmark West Texas Intermediate crude oil lose two-thirds of its value. RBOB futures also saw their value decrease by two-thirds during the quarter while ULSD prices gave back about half their value.
"Given the severe downturn in oil and gas prices driven by uncertainty around the duration of the Saudi/Russia oil price war and the COVID-19 pandemic, the company's board of directors came to the conclusion that the principal terms of the financial restructuring negotiated with our creditors provides the best path forward for the company," said CEO and President Bradley J. Holly.
In its announcement, the company said it has reached an agreement with noteholders on a "comprehensive restructuring" that would reduce company debt and "establish a more sustainable capital structure."
Among the things called for in the plan is for Whiting's existing shareholders to receive a 3% equity stake in the reorganized company. It also calls for "de-leveraging of the company's capital structure by over $2.2 billion through the exchange of all of the notes for 97% of the new equity of the reorganized company," and payment to all other secured creditors and employees.
"Through the terms of the proposed restructuring, we believe a right-sized balance sheet will enable us to capitalize on our enhanced cost structure, high-quality asset base and successfully compete in the current environment," Holly said.
Stock in the company, which had reached a 52-week high of $30.94 per share about a year ago, ended the session Tuesday at 67cts per share. The stock was off more than 43% Wednesday afternoon, trading at 38cts/share.Whiting's announcement marks the first high-profile company to fall victim to the ongoing dispute between Russia and Saudi Arabia, which began in March after Russia refused to go along with an OPEC plan to cut production to support energy prices during the virus-related fall in global energy demand.
It is expected other American shale producers, who face higher production costs than many other global producers, will also fall victim to the price war.
The WTI break-even price for U.S. shale plays is now about $42.41/bbl, according to IHS Markit data, about $10/bbl lower than where it was two-and-a-half years ago and about $37/bbl less than in January 2012. But break-even prices vary by play, from a low of $26.85/bbl for producers in Eagle Ford in Texas to $147.18 in the Powder River Basin in Wyoming, according to IHS Markit, which is the parent company of OPIS.
"With a sustained price downturn, bankruptcies among the privates and perhaps some publics, should accelerate, and consolidation could kick in," Citi Research warned at the start of the price war. Much of the impact won't be apparent until later in the year or if the price war continues into 2021, since many producers will benefit from hedging for 2020 done at higher prices, Citi had said.
The drop in energy prices prompted several shale producers to announce cuts in capital spending in an effort to firm up balance sheets for the tough times ahead. Whiting on March 16 had announced $185 million in cuts to planned capital spending.
Whiting's operations are located primarily in the Rocky Mountain region. Its largest projects are in the Bakken and Three Forks plays in North Dakota and the Niobrara play in northeast Colorado.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Steve Cronin, scronin@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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European refiners have been reducing their runs in the past few weeks on the back of falling demand amid the coronavirus disease 2019 (COVID-19) outbreak. The following list is a snapshot of the main announced and heard developments.
--The major turnaround at the Shell-operated 404,000-b/d Pernis refinery in Netherlands, Europe's largest plant, has been brought forward and will begin on April 13, OPIS reported on March 30. The turnaround will take longer than previously expected because of the pandemic necessitating social distancing measures, OPIS sources say.
--Major works due to take place in April at the 210,000-b/d Grangemouth refinery in Scotland and construction of a new 350 million-pound power plant have been postponed. At least one unit is heard offline.
--Phillips 66 has confirmed run cuts in its refining system as part of actions taken in response to the challenging business environment. OPIS has learned that the refiner has pushed back a turnaround scheduled for April-June to September because of the pandemic.
--The U.K.'s largest oil refinery, the 270,000-b/d Fawley plant, has cut runs but remains online after discussions between operator ExxonMobil and British government officials. ExxonMobil cut refinery runs at Fawley by around 70,000-b/d at the beginning of the week after taking the Pipestil 1 unit offline. Fawley is a critical part of the U.K.'s energy infrastructure because of its links to the nation's largest cities and airports. Eighty-five percent of the refinery's output is pumped through underground pipelines as far away as London, Birmingham and Bristol. Pipelines connect the refinery to Heathrow and Gatwick airports. Diesel represents 29% of the refinery's output, while gasoline, jet and petrochemical feedstocks make up 28%, 11% and 9% of output.
--A planned turnaround at Total's 100,000-b/d Feyzin refinery was stopped around March 20. Total said in an internal letter that it was "impossible" to say when the works would resume. The maintenance at the refinery started on Feb. 14 and was expected to last seven weeks, Total had previously confirmed. The French major previously allocated 80 million euros for the works.
--ExxonMobil said on March 20 that it was cutting runs at its two French refineries, the 133,000-b/d Fos-sur-Mer plant and the 239,000-b/d Port Jerome refinery.
--On Monday, March 23, local media reported that Total was delaying bringing the 120,000-b/d Grandpuits refinery back online following a planned month-long maintenance due to plummeting demand.
--The fluid catalytic cracker (FCC) at Repsol's 120,000-b/d Coruna refinery in Spain began maintenance in January for two and a half months and is still in maintenance, a Repsol spokesperson told OPIS on March 30, adding that the refinery is operating at a reduced capacity. Sources reported that other Repsol plants are affected. Repsol has five refineries in Spain -- the Coruna, Puertollano (157,000 b/d), Tarragona (160,000 b/d), Petronor (220,000 b/d) and Cartagena (220,000 b/d) refineries.
--BP's 105,000-b/d refinery in Castellon, Spain, was adjusting production to respond to a sharp fall in jet consumption, local media reported.
--Cepsa is also looking at run cuts, local media says. Cepsa has two refineries in Spain -- the Huelva (220,000 b/d) and Gibraltar (240,000 b/d) plants.
--Italy's 315,000-b/d Sarroch refinery, operated by Saras, was heard still carrying out a partial turnaround in March.
--Finland's Neste said on Monday, March 23 that it would delay the major scheduled turnaround at its 206,000-b/d Porvoo refinery and would do only the most business-critical maintenance works planned for April- June.
--Norway's largest refinery, the 230,000-b/d Mongstad refinery, has trimmed run rates, OPIS heard at the end of March.
--Ralf Schairer, head of the 320,000-b/d Miro refinery in Karlsruhe, Germany, told local media on Tuesday, March 24 that fuel sales from the facility in April are likely to be up to 50% lower than in previous years. Schairer also estimated that the facility needs to cut staffing levels in half to minimize the risk of infection.
*** Get instant updates on refinery unit outages as well as a complete list of planned and unplanned U.S. Refinery Maintenance with the OPIS Refinery Maintenance Report:
--Reporting by OPIS Staff, OPISReporter@ihsmarkit.com;
--Editing by Anthony Lane, alane@opisnet.com
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U.S. refining is entering a new phase of the fallout from coronavirus disease 2019 (COVID-19) -- full idling of processing units and plantwide shutdowns will be next, industry sources say.
The last week has been rife with reports of operating rate reductions within company systems -- reportedly in a range of 10% to 30% -- and yield shifts to maximize production of diesel in the face of sliding consumption of gasoline.
Phillips 66, PBF Energy and Par Pacific have confirmed reductions, while similar actions have been reported for Valero, Marathon Petroleum, Monroe Energy and ExxonMobil.
But as the first quarter of 2020 comes to a close and much of the country braces for the intensification of the pandemic through at least April, those overall rate reductions are expected to widen and deepen for some types of units.
The focus of the temporary unit shutdowns so far appears to be fluid catalytic cracking units, or FCCs, which are the workhorse units behind the majority of refineries' production of gasoline products.
Having represented quite a bit of first-quarter planned maintenance, FCCs are in some cases not being restarted after turnaround. Word of other kinds of units temporarily extending downtime is also beginning to circulate, industry sources told OPIS.
OPIS estimates the amount of FCC capacity down as of today due to run cuts is a little less than 400,000 b/d, according to Refinery Maintenance Report data.
The total amount of FCC capacity offline (including maintenance) is just under 990,000 b/d, according to OPIS data.
Total U.S. crude capacity not in operation currently comes to about 1.87 million b/d, of which about 270,000 b/d is due to run cuts.
Just how much more FCC capacity and overall refinery processing will slow is difficult to predict, but recent forecasts and indicators suggest that a rough halving of U.S. gasoline consumption is not out of the question.
As reported last week, OPIS parent company IHS Markit has projected that gasoline demand could decline by as much 4.1 million b/d during what it calls the COVID-19 response period.
OPIS data showed the national average volume of fuel sold in the U.S. was off by 24.1% in the week ended March 21 compared to the same week in 2019. The decline measured against the previous week came to 21.9%, according to an exclusive OPIS survey of more than 15,000 retailers nationwide.
Regional sales data showed deeper declines for the West (including California and Washington) at almost 30% year on year, and for the Northeast at 26.4%, where a number of refinery run cuts have been reported. Gasoline sales declines in the country's interior were a little lighter: 24% year on year in the four-state Southwest region and 23.2% in the Midcontinent.
As for full-plant temporary shutdowns due to COVID-19, North America has its first in North Atlantic Refining Ltd.'s 130,000-b/d Come by Chance refinery in Newfoundland. The refinery, which supplies cargoes of gasoline and diesel to the U.S. East Coast and sells distillate to European buyers, will maintain a reduced staffing crew on site to maintain equipment.
As reported by OPIS on Monday, earlier in March Come by Chance adjusted yields so that it wasn't manufacturing significant amounts of jet fuel. The refinery doesn't have an FCC.
*** Get instant updates on refinery unit outages as well as a complete list of planned and unplanned U.S. Refinery Maintenance with the OPIS Refinery Maintenance Report:
--Reporting by Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Steve Cronin, scronin@opisnet.com
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New technologies, by way of instant access to high frequency data and big data, is allowing companies for the first time, in a crisis, to swiftly make better-informed decisions that prevent resource wastage and bottlenecks, while making it easier to spot and leverage arbitrage opportunities.
The demand devastation wreaked by the coronavirus disease 2019 (COVID-19) is there for all to see and technology has kept decision makers aware of trigger points in almost real-time, thereby allowing rapid decisions to manage their supply chain, industry sources said.
"Demand is assessed so quickly and decisions made so rapidly that it prevents unnecessary deployment and use of resources," said one source. "The resources can be redeployed with the same speed when demand starts rebounding in the aftermath of this crisis."
"I have seen both the 2008 crisis and this one....and can tell you there is a quantum difference in response times. The world economy is much more nimble and efficient 12 years down the line," he added.
For example, a day after Indian Prime Minister Nerendra Modi announced a lockdown of the nation of 1.3 billion people, the nation's biggest oil refiner, Indian Oil Corp. (IOC), said it was cutting operating rates by 25-30%.
IOC's decision is based on both real-time data they are getting from their customers and also from the scale of fuel demand destruction seen in other nations that have gone through similar lock downs such as China, the sources said.
Chinese refiners used high frequency data such as passenger transportation usage and internal retail numbers to assess the scale of demand destruction on a daily basis to tailor their output and procurement plans accordingly, they said.
"A lot of companies are demanding a lot more visibility of what's going on, in terms of inventory and then they figure out their production. Companies are less likely to be completely blind this time around," said a senior executive at a specialty oil production company.
"The problem is usually the lag, sales don't tell the planners who can't talk to manufacturing and this then affects procurement. Now top management are well aware, today we have more coordination meetings and decisions are made instantaneously," he added.
In China, for example, integrated oil refiners such as Sinopec and PetroChina used data from their own network of retail outlets to gauge consumption patterns on a real-time basis, much faster that high-frequency data obtained from government agencies, to decide on operations, said Feng Xiaonan, IHS Markit downstream analyst in Beijing.
"Sinopec had high-level meetings, directing and playing the role of a coordinator to smooth things out. For example, asking Unipec to adjust crude purchase to align with refining requirements, while still giving individual refineries discretion over their operation as they can respond to local circumstances much faster such as storage levels, travel restrictions," Feng said.
"Even then, nobody anticipated it would happen this fast, and when it first happened, comparisons were made to SARS, again nobody expected the virus to spread so wide and so fast," she added.
These new technologies including instant data sharing allow companies to react faster in making informed decisions, Feng said.
Within the oil refining sector, such quick decisions were seen throughout the supply chain. In the case of China, as the industry got to grips with the speed and scale of demand destruction, actions came thick and fast including deferral and cancellation of crude oil purchases, overseas sales of surplus oil products and tweaking refinery slates to minimize output of worst hit fuels.
Refiners in Europe, the U.S. and India are now doing what Unipec did over a month ago in seeking to manage their supply chain, with talks emerging of force majeures and drastic run cuts, while others are seeking to back out or sell surplus crude cargoes, market sources said.
This, they said, would fuel the contango market further and induce more participants to look into storing crude oil for future sales.
"The big traders are so quick to seize upon the opportunity of oil that is almost free, to make a killing later down the line when things come back to normal," said one ship broking source.
For example, Shell booked the very large crude carrier (VLCC) Maran Corona for a voyage from the U.S. Gulf Coast to East Asia with storage option, while Hess has the Desimi on charter for the same journey for $15.25 million that includes 60 days storage at $95,000/day, a fixture list released on Friday showed.
This compares with a charter by Glencore, about two weeks ago for an ultra large crude carrier (ULCC) for $37,000/day for at least six months, which worked out to a carrying cost of about $0.40-$0.50/bbl per month compared with current six-month contango at around $10/bbl.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Spot US benzene prices for April delivery reached 87 cts/gal DDP HTC on Monday, the first dip below the $1/gal level so far this year and the lowest price seen since early 2009. Benzene has been beset by weak demand worldwide and coupled with the slump in crude markets, price support for the commodity has crumbled. Like crude, US benzene's forward curve is in contango, with May closing at 90 cts/gal and June at 94 cts/gal on Monday, according to IHS Markit’s North American Aromatics Report.
European benzene prices dipped below $200/mt (67 cts/gal) on Monday, which weighed on US prices in this region as it will keep an arbitrage open to move product to the US Gulf Coast. An estimated 30,000–35,000 mt of benzene is expected to move from Europe to the USGC in coming weeks, although ship space is becoming limited. Traders and producers are already leaning on floating tanker storage, and as storage gets tighter it could push prices down further. Asia benzene pricing is still above North America but pricing in this region is sensitive to prices falling in Europe.
Spot ethylene prices have moved into single-digit territory, with April trading at 9.25 cts/lb (27.5 cts/gal equivalent) at Mont Belvieu, according to OPIS PetroChem Wire. These are historic lows for ethylene; previous lows in past years were 10 cts/lb. Steam cracker operating rates were still relatively high in the USGC, with only three of the region's 50 olefins units shut (for maintenance). Ethylene's forward curve is also in contango, however slight. May ethylene at the Mont Belvieu NOVA hub was 9.5 cts/lb and June was 9.75 cts/lb.
Even at these prices, ethylene was still a marginally profitable commodity: April production costs using ethane were 6.6 cts/lb on Monday, while costs using propane were 6.8 cts/lb. Costs using butane were 8.7 cts/lb and costs using natural gasoline were 5.1 cts/lb, according to OPIS’ NGL Forwards Report.
In contrast, spot propylene prices rebounded somewhat, moving from a 2020 low of 19 cts/lb last week (82.6 cts/gal equivalent) to 20.5 cts/lb FOB Mont Belvieu on Monday afternoon. Little interest has been seen for prompt polymer grade propylene but deals for 2Q and beyond combined with spread trades have buoyed front-month pricing.
Downstream, US polymer demand has held up despite the weak upstream price environment. According to OPIS PetroChem Wire, spot linear low-density polyethylene was 40 cts/lb on a delivered basis East of the Rockies, spot homopolymer polypropylene at 44.5 cts/lb and spot general purpose polystyrene was 60 cts/lb.
OPIS PetroChem Wire's Daily Wire provides closing prices and a summary of the day's trading activity for US ethylene, proylene, polymers and upstream NGLs markets. Begun in 2007, its olefins and polyolefins prices serve as benchmarks for a number of physical and swap contracts that trade on the CME/NYMEX Clearport system.
--Reporting by Julia Giordano, julia@petrochemwire.com, David Barry, david@petrochemwire.com and Kevin Wallman, kevin.wallman@ihsmarkit.com;
--Editing by Kathy Hall, kathy@petrochemwire.com and Joe Link, joe@petrochemwire.com
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Rack-to-retail margins across the United States are beginning to soften after soaring to record highs in recent weeks amid the steep, sudden drop in prices for crude oil and refined products.On Monday, the gross national average rack-to-retail margin for regular unleaded was 81.4cts/gal, with the national state high at $1.31/gal in Utah while Ohio's 50.6cts/gal was the national state low, according to OPIS MarginPro data.
The gross national margin is 14.1cts/gal off the national record-high margin of 95.5cts/gal hit on March 23, according to OPIS data. But it is still more than 22cts/gal higher than what had been the gross national daily record before the start of the month, when markets were hit by the one-two punch of the outbreak of a price war between Russia and Saudi Arabia and a sharp drop off in global energy demand due to global efforts to fight the coronavirus disease 2019 (COVID-19).
Heading into the month, the previous record margin had been 59.3cts/gal set on Oct. 6, 2008, at the start of the global financial crisis that led to the great recession. It's an indication of just how strong gross margins have been during March that the national average for the month through March 28, 64.15cts/gal, is 4.85cts/gal higher than the old record, according to MarginPro data.
Average national margins started the month at 35.8cts/gal and sank as low as 27cts/gal before rocketing upward. The national gross margin first shattered the old record on March 11, when it jumped from 55.1cts/gal to 67.8cts/gal, a climb of 12.1cts/gal. It jumped again on March 16, popping up 14.5cts, and then added 9cts/gal on March 23 to set the new record. The national margin spent two days above the 90cts/gal mark before dropping 8.9cts/gal, to 83.8cts/gal on March 25, the OPIS data shows.
The rise and fall of the national gross margins were largely reflected by trend lines in all regions across the United States, the MarginPro data shows.
In the Western region, regional gross average margins started the month at 46.4cts/gal, went as high as $1.193cts/gal on March 23, and are now $1.123cts/gal, according to OPIS data.
Regional gross margins in the Northeast were at 42.3cts/gal on March 1, hit $1.124 on March 23 and are now 93.5cts/gal.
In the Southeast, the average gross regional margin was 28.8cts/gal at the start of the month, peaking at 83.6cts/gal on March 23 and falling to 69.7cts/gal today, OPIS data shows.
In the Great Lakes region, the average gross regional margin was 35.2cts/gal on March 1, peaked at 80.3cts/gal on March 23 and is now 64.2cts/gal.
The Midwest region saw the gross regional margin at 35.1cts/gal at the start of the month before climbing as high as 96.4cts/gal on March 23 and falling to 85.3cts/gal today.
In the Southwest, the average gross regional margin was 29cts/gal at the start of the month, rose to 85.3cts/gal on March 23 and then settled at 72.8cts/gal today, according to the MarginPro data.
The climb in margins, however, comes at a time when all regions in the nation are seeing sharp declines in demand.
Nationally, the national average demand at fueling stations fell by 21% during the week ending March 21, with demand being off 24.1% compared to the same week in 2019, according to OPIS DemandPro data. Nationally, stations sold an average 19,840 gallons during the week ending March 7, compared to 15,646 gallons during the week ending March 21.
In the Western region, stores saw volumes fall 30% behind the same week last year, with sales of 19,807 gallons a sharp 23.2% decline from the 25,797 gallons sold during the week ending Feb. 29, OPIS data shows.
In the Northeast, average demand fell by 26.4% during the week ending March 21, when compared to the same year in 2019. Stations in the region sold an average 15,836 gallons during the week, compared to 20,156 gallons during the last week of February, a loss of 27%.In the Southeast region, sales lagged 20.1% behind the same week in 2019. Stations sold an average 14,475 gallons during the week, compared to 17,768 during the week ending Feb. 29, a decline of nearly 22.75%, according to OPIS data.
In the Midcontinent area, which includes the Great Lakes and Midwest regions, sales were 23.2% behind a year earlier, while the 14,457 gallons sold is off the 18,444 sold at the end of last month, a 27.6% decrease.
In the Southwest, station sales during the week ending March 21 were off 24% from the amount sold the previous year. Stations sold an average 15,678 gallons during the week, compared to 20,326 gallons at the end of February, a whopping 29.6% retreat, OPIS data shows.
The shakeup in national and regional sales, however, hasn't led to much change in market share holdings by the top brands. Nationally, the top three brands in store market share rankings for the month ending Thursday were Shell, with a 7.58% market share, Circle K with 7.42% and Speedway with 6.08%, according to OPIS MarketsharePro data.
That's compared to Shell with 7.66%, Circle K with 7.23% and Speedway with 6.12% a month earlier and Shell, with 7.77%, Circle K with 6.65% and Speedway with 5.81% a year earlier, the OPIS data shows.
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--Reporting by Steve Cronin, scronin@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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California Carbon Allowance (CCA) prices are clawing back after a shocking exodus of financial players recently capsized seven years of policy-regulated inflation and exasperated pandemic-induced chaos in the California-Quebec Cap-and-Trade Program.
CCA bids inched higher Monday in the secondary market, after prices regained about $4.50/mt last week from an unprecedented deterioration of more than $6.50/mt since early March -- when fears of the coronavirus disease 2019 (COVID-19) surfaced. As the virus spread, trade volatility and liquidity escalated, causing massive waves of market uncertainty.
The crash hit a crescendo on March 23, when prompt vintage current year CCAs traded at $11.05/mt -- a price unseen since the inception of the emissions trading scheme. Four weeks before, on March 2, OPIS assessed the value at $17.82/mt.
When the air began to clear last week, noticeably absent were the financial players that arrived in a similar fervor last year with bouts of capital to buy into the carbon reduction program.
During the last 12 months, the groups -- like hedge funds -- placed many sure bets in forward positions, with an understanding that officials designed the cap-and-trade program with a rising price structure.
'Stop the Bleeding'
"The 'new money' that came in last March was over leveraged and when the prices dipped, they got margin called and stopped out and took down the market with them. ... Then, Sunday night some brokers and consultants got together a larger purchase to stop the bleeding and put some support into the market," a CCA trader said last week.
On the night of March 20, millions of CCAs traded on the Intercontinental Exchange (ICE), where the majority of the secondary market transacts, the trader said.
An ICE spokesman did not respond to comment on the trade volume or the potential effect of updated margin rates for ICE Futures U.S. Emissions Contracts that went into effect on March 23 -- the day CCA prices started to rebound.
The week before -- when CCAs took the largest nosedive -- 100 million CCAs exchanged hands "which is close to what we think the speculative length was in the market," analyst firm Clearblue Markets Managing Director of Markets Nicolas Girod told OPIS. Volume during a typical trading week is between 5 million and 10 million allowances, he said.
"I think most of the longs that wanted to go out have now liquidated," Girod said. "Once all these [speculators] are out, prices could come back closer" to the 2020 California-Quebec joint Cap-and-Trade Program Auction Reserve Price (ARP) of $16.68/mt.
CCAs in the Basement
It was a rare contrast to cap-and-trade policy design, when CCA secondary market prices dropped below the ARP level on March 17.
The ARP sets the floor of four quarterly CCA auctions per year, a mechanism meant to buoy prices so compliance entities make facility emissions cuts instead of purchasing allowances. In theory, the secondary market price should remain well above not only the corresponding auction floor price but also the auction settle, which was $17.87 for the Q1 2020 event.
If the secondary market price remains below the ARP at the time of the second quarter CCA auction in May, the event could be lightly bid, CCA secondary market participants recently said. This would present another diversion from the program's history, as nearly every auction has sold out since 2013.
"Who would bid the next auction if spot is trading $1 lower?" another CCA trader said.
Meanwhile, U.S. West Coast fuel suppliers told OPIS that they were considering the impact of sharp demand declines and fuel sales on their cap-and-trade obligations, and that the possibility of lower obligations for various types of compliance entities due to COVID-19 mitigation orders in California was likely helping put pressure on prices.
The most recent California retail demand analysis by the OPIS DemandPro service showed an 8.4% decline in same-store fuel sales at West Coast retail stations for the week ending March 14. Stringent social distancing measures enacted in the state are expected to further quell fuel demand.
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--Reporting by Bridget Hunsucker, bhunsucker@opisnet.com;
--Editing by Kylee West, kwest@opisnet.com
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Clean petroleum product tankers are being snapped up at a frantic pace as participants look to store distressed cargoes for future sales amid a wide contango that has made such actions profitable, according to market sources and fixture lists.
The charters coincides with moves by refiners in Asia offering cheap barrels of transportation fuels due to swift demand erosion in the face of social distancing measures, including lock downs, that governments in several countries have put in place to control the spread of the coronavirus disease 19 (COVID-19), they said.
At least seven clean tankers were put on provisional charter for storage of up to 180 days, according to a shipping fixture released on Monday, which market sources said was the biggest such booking in one day in years.
Glencore, for example, has the LR2 Eternity and STI Carnaby for 120-180 days storage off Singapore at $44,000/day and $40,000/day, respectively, the list showed. BP, on its part booked the BW Larissa and Celcius Everett for 60-120 days storage at $50,000/day and $46,700/day, according to the fixture, without specifying a location.
Both the BW Larissa and the Celsius Everett are currently in the Sea of Japan, according to IHS Markit ship tracking data.
Shell has the FOS Athen booked for 90-120 days to store 47,000 mt at $52,500/day while Vitol has a yet to be named LR2 on subject also for storage, the fixtures show.
The rates are much higher than that secured about two weeks ago as the influx of bookings by traders to move cargoes West and to store barrels as part of a contango play drove rates higher.
A fixture list released on March 19 showed that BP and Shell took an LR1 each in the West to store 60,000 mt of jet fuel. BP booked the Stena Polaris for 45-90 days at $25,500/day, and Shell the Torm Sara for 90-120 days at $35,000/day.
Even with the higher floating storage costs, traders can still make a profit by storing cargoes for sale in the future due to the wide contango. The Singapore three-month April to July jet fuel contango was $6.81/bbl, while that of gasoline was $4.15/bbl and diesel at $2.79/bbl, according to broker data on Monday.
This works out to about $18/mt per month for jet fuel, $11.75/mt for gasoline and $7/mt for diesel versus storage costs at around $14.70/mt based on Glencore's booking of the Eternity for 150 days.
At the same time, weakness in the physical market has pushed differentials deep into the negative territory with cargoes on an FOB China basis pegged at minus $15.60/mt for jet fuel, $12.30/mt for gasoline and $11.25/mt for diesel, according to traders.
In the face of a dearth of demand in Asia, traders are moving cargoes West at pace and some of these could end up in storage when they arrive in Europe about a month from now, market sources said.
Hefty and potentially record volumes are being lined up for shipment with 980,000 mt of diesel and 390,000 mt of jet fuel scheduled to load in the first half of April bound predominantly for Europe from the Middle East, India and East Asia, according to shipping fixtures.
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--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com, John Koh, John.Koh@ihsmarkit.com;
--Editing by Wu Hanwei, Hanwei.Wu@ihsmarkit.com
Copyright, Oil Price Information Service
MEXICO CITY - Mexico's diesel demand was struck during March's second week with a year-over-year (YOY) drop of 50%, reaching 224,000 b/d as supply chain disruptions and factory closures affected the country's economic activity due to the global economic slowdown caused by the coronavirus disease 2019 (COVID-19).
In 2019, diesel fuel demand for the second week of March was strong at 450,000 b/d, and the highest for that year. However, diesel consumption during the second week of March 2020 was 45% lower than the average March 2019 demand, preliminary data from Mexico's Energy Secretariat (SENER) showed.
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Industrial regions have been hit the hardest. The auto sector powerhouse of Western Mexico consumed 22,000 b/d of diesel, a drop of 80% YOY. Meanwhile, Northeastern Mexico, home to the country's largest industrial companies, consumed 35,300 b/d of diesel, a YOY drop of 46.6%.
Lower diesel demand happed while companies like Audi and Honda were affected by supply chain disruptions from Wuhan, the epicenter of China's auto sector. Both companies closed their auto plants during the third week of March, according to media reports.
Sources told OPIS that Mexico diesel demand is being impacted by the direct damage COVID-19 inflicted on international supply chains. In comparison, gasoline demand has fallen 3.7% YOY to 768,500 b/d during the second week of March.
This week's Mexican gasoline demand estimate could be around 645,000 b/d - 18% lower compared with 2019, according to an OPIS analysis based on preliminary sales data from ONEXPO, Mexico's largest fuel retail association.
One of Mexico's leading national fuel wholesalers told OPIS they experienced a significant drop in diesel sales, adding that the demand picture is worse today than at the beginning of the month.
At the time, one of the national wholesaler's new freight clients requested 1/8 of its contracted volume while a passenger transportation company was billing 25% of their usual demand.
"Today, we see the impact on the coronavirus pandemic," the wholesaler said.
"With a rough calculation, we are seeing today a demand drop today of at least 50% compared with a year ago."
A second wholesaler told OPIS that he has also experienced a significant drop in diesel sales. "We aren't going to realize the whole damage until we see consecutive weeks of quarantine."
The most worrisome part about diesel demand drop is that this is just the beginning, Victor Gomez Ayala, deputy director for economic analysis with Mexico City-based brokerage firm Finamex, told OPIS.
"Mexico's industrial heartland hasn't stopped beating, but it is showing clear signs of a COVID-19 infection," said Gomez, who is the former chief economic adviser to Mexico's Revenue Undersecretary at the end of Enrique Peña Nieto's administration.
Despite a lack of strict quarantine measures at the time, the Mexican economy has already been impacted by COVID-19 via the global supply chain. "We don't expect a fast recovery but rather an increasing downward trend in refined products," he added.
Mexico's manufacturing sector is highly integrated with the rest of the world, connected to countries like Germany, Spain, France, Italy, Japan, South Korea, and the U.S, especially Western Mexico, Gomez said.
"Although we haven't seen a lockdown in Mexico, the industry is undergoing a difficult moment," Gomez said. "This is just the start, and we have to see what the local impact will be with the growing numbers of coronavirus and stricter quarantine measures."
A concern related to lower fuel demand is going to be the resulting lower fuel tax revenue collected by Mexico's Federal government via the IEPS tax, he added.
In 2019, Mexico collected via the IEPS fuel sales tax over Peso 297 billion, US $15 billion based on that year's average exchange rate.
"If the fuel demand collapses, which is something likely, one has to consider the important effect this will have in the government excise fuel tax revenue," he added
President Andres Manuel Lopez Obrador has said he won't raise fuel taxes to fulfill his campaign pledge of keeping low energy prices.
"With lower fuel demand, Mexico could compensate some of its lost IEPS revenue via a higher Pemex's fuel marketing margin considering its dominant market position," said Gomez.
OPIS estimated that Pemex's share of the total gasoline and diesel supply represented 84.9% and 66.2% of the national demand in January, respectively, based on government data and customs information on private fuel imports.
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--Reporting by Daniel Rodriguez, drodriguez@opisnet.com;
--Editing by Lisa Street, lstreet@opisnet.com
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The crash in oil prices is threatening to erase the US advantage for chemical feedstocks and olefins, but plastics demand is carrying the day, posited a team of analysts at Citi Research, a division of Citigroup Global Markets Inc., during a recent conference call titled "The Double Whammy Impact of a Lower Oil & Covid-19 on NGLs and Petchems".
While US ethane at 9 cts/gal may be oversold, noted Tony Yuen, Citi's Head of Commodities Strategy Pan-Asia, US propane and butane have "further room to fall" as naphtha becomes a globally competitive chemical feedstock again.
"The US propane market relies on the export market to balance because without the export market, inventory injection could be more than a million barrels a day at a time when propane inventory is already high after a mild winter," he said. "So what that means is that through the export arbitrage condition, you have low oil prices, which drag down naphtha prices, which then drag down propane prices. Then if you take out the export shipping cost from the US to Asia, you come to the US, where propane prices should be much, much lower than where we are right now just through these types of analysis."
Still, "there’s a tremendous amount of unknowns right now on the midstream side," said Timm Schneider, Citi's Head of Energy & Utility Equity Research for the Americas. Estimating current output levels of roughly 1.8 million b/d of ethane production and 1.7 million b/d of propane and combined 1.5 million b/d of butanes and natural gasoline, Schneider said he believes fractionating units, known as fracs, will begin throttling back. Fractionator utilization “could decline to about 70%. We’re probably running in the 90-95% range right now, so most of these fracs are heavily utilized," he said.
According to data from PointLogic, production of propane, as well as all other NGLs, has not been significantly impacted by the downturn in energy prices. Propane production has been on either side of 1.7 million bbl/day since March 6. However, PointLogic data show that NGL production declined by nearly 2% from March 23 to March 25.
Schneider stated that storage, especially at Mont Belvieu, will be crucial to the health of the US NGL markets. "One big thing to me is having the ability to have storage," he said. "And that’s especially true if we do see some of this contango that’s happening in the oil markets potentially push into the natural gas liquids and purity product side."
Despite the falling NGL prices, the US' cost advantage over Europe and Asia is fading. "At the peak, US advantage was north of $500 per ton and now it’s below $200 per ton," said P.J. Juvekar, Citi's Global Head of Chemicals. "If oil goes to below $20, that advantage pretty much goes away at a ratio of 10-to-1 on oil-to-natural gas price."
Still, the outlook isn't all gloomy. "Lower oil prices does create some winners as well," Juvekar noted. "And one of the big winners was the paint companies and some of the specialty companies that use oil as raw materials, and their margins could expand." That said, 2Q demand forecasts are quite bearish and "the US is going to shut down" in Juvekar's words, pushing that demand out to later in the year. "Even for paint companies, we think paint season could get delayed here as we get into the spring."
However, the effects of worldwide quarantines and widespread illness are supportive of plastics demand, Juvekar said. "so far we haven’t seen a decline in polyethylene demand... a lot of flexible packaging is being used and also a lot of medical packaging,” he said.
The Citi team's comments on supply chain trends line up with what OPIS market reports are showing. The typical demand boost from Asia seen at the end of the region's Lunar New Year holiday in mid-February didn't materialize, and as the pandemic's curve began in Europe during February and now in the Americas in March, worldwide demand is depressed for most markets.
According to OPIS data, March purity ethane prices have dropped from 15 cts/gal in mid-February to a low of 9 cts/gal late last week, and have now stabilized at around 11-12 cts/gal this week, bearing out Yuen's comment about the product possibly being oversold at 9 cents.
Propane has shed nearly half of its value during the same timeframe, dropping from the low 40s cts/gal range in mid-February to the low 20s cts/gal zone this week. If the slide continues and fractionators begin cutting rates, propane's contango shape throughout the 2020 market echoes Schneider's comments about the importance of storage availability to support weak price environments. Similarly, for normal butane, OPIS data shows prices for current month delivery sliding from 65 cts/gal in mid-February to a record low of 16 cts/gal this past Tuesday. Since then, butane has come back up to the low 20s cts/gal range.
The trends in NGLs extend into the US Gulf Coast olefins markets, as front-month ethylene at Mont Belvieu fell from an already weak 14.5 cts/lb (43 cts/gal equivalent) to a record low of 10 cts/lb (29.7 cts/gal) and Mont Belvieu polymer grade propylene prices dropped from 35 cts/lb (152.25 cts/gal equivalent) to 19 cts/lb (82.6 cts/lb), according to OPIS PetroChem Wire data.
Plastics prices have been more resilient, for the reasons pointed out by Juvekar. Spot polyethylene has eased a bit, but not to the extent seen upstream. The linear low density grade PE market, used in flexible packaging production, has seen spot prices move from 33 cts/lb (98 cts/gal) in mid-February to 30 cts/lb in early March and currently sits at 28 cts/lb (83 cts/gal), basis FOB Houston. Spot polypropylene is more vulnerable to collapsing demand as it depends on automobile and durable goods manufacture for part of its consumption, but prices so far have only moved from 43 cts/lb (187 cts/gal) to 40 cts (174 cts/gal). Operating rates for US olefins and plastics plants remains high, at 90% or above as a whole.
OPIS PetroChem Wire's Daily Wire provides closing prices and a summary of the day's trading activity for US ethylene, proylene, polymers and upstream NGLs markets. Begun in 2007, its olefins and polyolefins prices serve as benchmarks for a number of physical and swap contracts that trade on the CME/NYMEX Clearport system.
--Reporting by Julia Giordano, julia@petrochemwire.com, David Barry, david@petrochemwire.com, Bobbie Clark, bclark@opisnet.com and Kathy Hall, kathy@petrochemwire.com;
--Editing by Joe Link, joe@petrochemwire.com
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A sudden surge in Indian liquefied petroleum gas (LPG) purchases is likely to give the prompt market a boost as people rush to stock up the cooking fuel but demand is expected to drop in the coming months due to the full lockdown of 1.34 billion people, industry sources said.
"In the midst of a reduction in demand for major petroleum products, there has been an increase in demand for LPG cooking gas," Indian Oil Corp (IOC) said in a press statement on Wednesday.
The company is taking steps to increase LPG yield from its major refineries even as it announced a 25-30% cut in crude throughput.
The Indian government placed the nation on a three-week lock down from Wednesday as they sought to control the coronavirus disease 19 (COVID-19) at an early stage in an effort to avoid a large-scale pandemic that is likely to overwhelm the country's health system.
Overall LPG production should still decrease due to the run cut, said market sources, adding that this could lead to larger imports to fill the supply gaps.
The April Saudi CP, which is the pricing basis for most Indian imports, was bolstered by $20/mt on Wednesday to $181/mt and remained in backwardation.
Indian term lifters have submitted a price of $150/mt for both propane and butane in their first round of April CP recommendations, which is well below that offered by other buyers that were in the range of $175-$250/mt for propane and $195-$240/mt for butane, according to sources.
Some market participants, however, believe that Indian demand will not deteriorate as much as China at the height of its COVID-19 outbreak as a lot more LPG is used in residences as a cooking gas in India.
In China, when traffic controls were imposed, a 21% drop per month was expected in the residential and commercial sector, and a similar scale could translate to 260,400 mt of demand loss in India, given its 91% concentration on residential and commercial uses, as OPIS reported earlier.
India consumed 2.11 million mt of LPG in Feb., a 14% drop on-month and a 4% drop on-year, according to the Petroleum Planning & Analysis Cell (PPAC).
Imports fell 3% on-month to 1.34 million mt in Feb., but was up 10% on-year, based on the PPAC data.
Gain greater perspective on global spot prices for naphtha, propane and butane.
OPIS developed the pricing in our Europe LPG & Naphtha Report to reflect the market’s desire for an unbiased methodology and accurate spot price benchmark in northwest Europe and the Mediterranean.
--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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IHS Markit, OPIS parent company, now estimates that global liquid oil demand points to a year-on-year contraction of more than 14 million b/d in the second quarter.
Given the current trajectory in supply, IHS Markit estimates that 2Q2020 global oil stock builds will be in excess of 12 million b/d.
Global markets face an eight-week blitz that could see overall stocks swell by 1 billion barrels cumulatively.
"Such an unprecedented build would overwhelm available storage capacity globally by the middle of the second quarter," IHS Markit calculates.
Oil markets will have to digest this surplus and price the reality that supply will need to be resolved.
IHS Markit believes that "some sort of management or partial management is likely to emerge as paralysis spreads across the sector, but lower prices and shut-ins are likely to occur first."
The market is already starting to see some petroleum refiners cut production and many upstream companies making big cuts in their exploration and production budgets.
Global oil prices have dropped sharply as a result of major shutdowns of activity across the globe including Australia, the U.S., and Europe - areas where COVID-19 has spread even as Asia recovers. India, however, is just what looks like the initial stage of a shutdown.
IHS Markit points out that it is yet to see "a workable path to coordinated supply action on the scale required to mitigate the physical challenge ahead."
Still unknown is whether Saudi Arabia and Russia will come back to the table to agree on some kind of production management strategy following talks falling apart in March with Saudi Arabia vowing to flood the market with more oil and reclaim market share via low prices.
Roger Diwan, vice president of financial services at IHS Markit said this: "The crux of the challenge for oil markets is twofold, the immense size of the surplus and the collapsed timeline of prospective builds, severely limiting the runway of the price war."
Diwan believes that the next few weeks are unlikely to provide material relief to bearish momentum as markets digest and price the reality that supply will need to resolve this balance.
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--Reporting by Ben Brockwell, bbrockwell@opis.net;
--Editing by Steve Cronin, scronin@opisnet.com
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U.S. biodiesel producers who use used cooking oil (UCO) are becoming increasingly worried that government-mandated restaurant shutdowns because of the coronavirus 2019 (COVID-19) outbreak are beginning to tighten supplies of the feedstock and could lead to reduced fuel production or plant closures.
A market source said biodiesel margins, which remained low despite the December enactment of legislation that restored the $1/gal federal biomass-based diesel blenders tax credit for 2018 and 2019 and extended it through 2022, have recently weakened to break-even or negative territory.
The source blamed much of the recent drop in margins to the ongoing crude production war between Saudi Arabia and Russia that has weakened prices for conventional diesel, but added that the economic hit caused by stay-at-home orders in the wake of the COVID-19 pandemic has "exacerbated" the drop in margins.
Now, producers that use UCO to make their product are having to deal with a growing number of state and local governments deciding to close restaurants or limit their service to delivery or takeout as part of social-distancing directives.
While those businesses that are still delivering food or offering takeout will continue to generate some UCO, sources say that won't be enough to prevent a major drop in the feedstock's supply over the next several weeks. Traditional restaurants, sources added, are unlikely to see the same demand for takeout as they usually would with in-house dining.
As a result, for producers that are already looking at how long they can continue to produce because of poor margins, a drop in feedstock supply may be enough to push them closer to shutdowns.
Jennifer Lapish, a manager at Thumb Bioenergy, said the Sandusky, Mich.-based producer has already scaled back production from around seven to ten batches of biodiesel a week to five.
She said the plant produced just over 500 million gal of biodiesel in 2019. But the latest developments have placed it and other producers in a difficult position.
"It's like whack-a-mole; every time we turn around, we get hit," Lapish said.
Jennifer Case, CEO at New Leaf Biofuel, said the San Diego, Calif.-based producer will have to do a few weeks of UCO collections before knowing the full impact from COVID-19 closures on feedstock availability.
"We have heard that pickup volume has fallen," Nancy Foster, president of the North American Renderers Association, said.
Foster said that part of the issue facing those who rely on UCO is that the product has traditionally been readily sourced, and thus there hasn't been a need in the past to store it in large amounts.
"I mean have you ever seen restaurants closed like this?" Foster asked.
The UCO shortage, or at least concerns that the material will soon become harder to source, have propped up prices for the feedstock, one source said.
The reported price for UCO should have mirrored recent declines in the price of soybean oil, but that hasn't occurred, likely because of future supply concerns, the source added.
Get accurate, up-to-the minute news, pricing and analysis for buying and supplying ethanol-blended fuel and biodiesel with OPIS Ethanol & Biodiesel Information Service. This service includes real-time news alerts, end-of-day pricing assessments, and a weekly newsletter and rack pricing report. Sign up now for a free 3-week trial now!
--Reporting by Patrick Newkumet, pnewkumet@opisnet.com;
--Editing by Jeff Barber, jbarber@opisnet.com
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The U.K.'s largest oil refinery, the 270,000-b/d Fawley plant, has cut runs but remains online after discussions between operator ExxonMobil and British government officials, OPIS can reveal.
Fawley refinery managers told workers at the refinery that officials representing the U.K. government have emphasized the need for the country to maintain continued supply of transportation products during the coronavirus disease 2019 (COVID-19) pandemic.
The communication from the refinery's managers comes after talk circulated the refinery that it was going to be shut down, say sources.
A source told OPIS this morning that ExxonMobil was preparing to make a statement underscoring "the vital operation Fawley provides."
In response to enquiries by OPIS, a spokesman for ExxonMobil sent the following statement: "We have robust Business Continuity Plans (BCPs) in place to deal with disruption events that have potential to impact critical business activities over the short or long-term -- including pandemic flu. All our BCPs are reviewed, tested and revised regularly.
"We have mobilised our pandemic flu BCPs at our manufacturing, operating and office sites in light of the increasing number of coronavirus cases in the UK," the statement said.
"Our contingency plans will help ensure continued supply of our products and to minimise any impact on our customers.
"Fawley is committed to helping meet the country's fuel needs, so medical staff and care providers can get to work, emergency services can stay mobilised, and the stream of vital supplies to hospital, medicines to pharmacies, and food and groceries to supermarkets, can continue," the statement concluded.
ExxonMobil cut refinery runs at Fawley by around 70,000-b/d at the beginning of the week after taking the Pipestil 1 unit offline.
Located on the English south coast, Fawley is a critical part of the U.K.'s energy infrastructure because of its links to the nation's largest cities and airports.
Eighty-five per cent of the refinery's output is pumped through underground pipelines as far away as London, Birmingham and Bristol. Pipelines connect the refinery to Heathrow and Gatwick airports.
Diesel represents 29% of the refinery's output, while gasoline, jet and petrochemical feedstocks make up 28%, 11% and 9% of output.
Gasoline and jet refining margins in northwest Europe have slumped into negative territory, OPIS data show. At the start of the week, the OPIS-assessed Eurobob gasoline crack was minus $11.85/bbl, while the jet crack was pegged at minus $1.58/bbl on Tuesday evening. By contrast, the diesel crack stood at $11.82/bbl.
ExxonMobil said on Friday that its 260,000-b/d Port Jerome Gravenchon refinery and its 140,000-b/d Fos-sur-Mer plant in France was going to reduce production.
"The group has implemented its planned procedures to ensure the continuity of its supply to our customers. It will continue to adapt its activity to take account of the evolution of (the) market or any supply, production or storage constraints," Exxon said in a statement.
Adrien Cornet, a CGT union member representing refinery workers, complained last week in a press release that French refiner Total was putting workers' lives at risk by making them work at the facility during the COVID-19 coronavirus outbreak.
On Monday, French media reported that Total was delaying the startup of its 120,000-b/d Grandpuits refinery following planned month-long maintenance due to plummeting demand.
Total was unavailable for comment.
A spokesperson for the German Petroleum Industry (MWV) said he was unable to confirm refinery run cuts in Germany, as the industry body receives data from refiners with a six-week lag.
Ralf Schairer, head of Germany's largest refinery, the 320,000-b/d Miro facility in Karlsruhe, told local media that fuel sales from the facility in April are likely to be up to 50% lower than in previous years. Schairer also estimated that the facility needs to cut staff levels by a half to minimize the risk of infection.
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--Reporting by Anthony Lane, alane@opisnet.com, Selene Law, slaw@opisnet.com;
--Editing by Paddy Gourlay, pgourlay@opisnet.com
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In a move right out of the Chinese playbook on the coronavirus (COVID-19) playbook, India has readied the almighty force majeure clause as 1.34 billion people get ready to deal with the consequences of a lockdown on a scale that the world has never seen before.
Amid all the chaos triggered by such stay-at-home orders is the need for governments to keep their supply chains moving, but port congestion and operational delays are inevitable as extra health checks are made on workers and others struggle to get to their work place as was the case in China when such measures were imposed locally.
"Major Port Trusts may consider COVID-19 pandemic as a valid ground for invoking Force Majeure Clause on port activities and port operations," the Shipping Ministry said in an e-mailed addendum dated March 24, as several orders were made, including the imposition of a 14-day quarantine before the lock down was mandated.
Industry sources said that India is laying the groundwork to save its industries from the perils caused by this virus as numerous Indian ports including Mundra, Krishnapatnam, Karaikal, Gangavaram and Dhamra triggered the clause on Tuesday as the government imposed a minimum three-week stay home order.
"It's a genuine situation brought about by circumstances beyond anybody's control, so they are in a way protecting the country's interest," said one shipping source, adding that the port force majeure is a means to limit claims of demurrage/detention or any other delays, which could send companies into bankruptcy if unchecked.
As China faced up to the worst of the COVID-19, the China Council for the Promotion of International Trade (CCPIT) announced that it would help affected companies apply for force majeure actions, which essentially excuses them from contractual obligations due to events beyond their control.
On Feb. 2, the CCPIT issued its first COVID-19 related force majeure, creating in the process a compilation of typical cases and assisting companies to effectively use the force majeure system in order to safeguard their rights and interests, according to a website posting dated March 13.
"As of March 3, 101 commercial certification authorities in the national trade promotion system have issued a total of 4,811 certificates of force majeure, involving contracts with a gross amount of approximately RMB 373.7 billion yuan ($52.9 billion)," the CCPIT said.
Sources said the Indian government, while allowing exceptions to facilitate the movement of key items such as food, medicine and fuels, is also bracing for the worst on expectations of sharp declines in the economy.
"The impact will also be quite dramatic as we saw in China. We will see a significant drop in oil demand in April, easily about 45-50% (year-on-year) drop in absolute demand of transportation fuels," said Premasish Das, IHS Markit research and analysis director in Singapore.
"We are talking about around 1.5 million barrels a day (b/d) of lost demand, and there will be a rippling effect." These are preliminary estimates as the lockdown is only in its infancy, he added.
The issues facing India are complex and imposing draconian measures may be difficult to enforce with government agencies issuing clarification and addendum to orders all Tuesday as compliance issues and problems were raised, sources said.
"Vehicles/trains/air cargo/ship cargo carrying goods for trade or essential goods and supplies are exempted from this prohibition along with their crew, driver, helper, cleaner etc. subject to their thorough screening by medical staff for COVID-19," the Ministry of Home Affairs clarified a Shipping Ministry order in a note to port operators.
For now, the energy sector is bracing for multiple disruptions including demand destruction, refinery run cuts, shipping delays and downstream closures if events in China were replicated, they said.
Although for now the number of COVID-19 cases in India are tiny at just over 550 compared with more than 81,000 in China, there are fears of an uncontrolled spread as seen in several European countries including Italy and Spain.
You have also seen how the most powerful nations have become helpless in the face of this pandemic," Prime Minister Narendra Modi said in a live televised address on Tuesday. "This lockdown will be for 21 days. This is to save India, save each citizen and save your family. Do not step outside your house."
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com; additional reporting by Thomas Cho, Thomas.Cho@ihsmarkit.com;
--Editing by Carrie Ho, Carrie.Ho@ihsmarkit.com
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Major turnaround work due to take place next month at the 210,000-b/d Grangemouth refinery in Scotland and construction of a new 350 million-pound power plant have been postponed amid the coronavirus disease 2019 (COVID-19) outbreak, OPIS has learned.
"The shutdowns are cancelled," a source told OPIS, referring to the turnarounds at the Petroineos-operated refinery and petchems plant.
The turnaround at Train 3 of the Ineos-operated Forties Pipeline System, which brings North Sea crude to the refinery, has also been shelved until later in the year.
The maintenance on the train was due to last up to 12 weeks and begin on March 29. OPIS revealed earlier this year that turnaround work at the refinery and petchems plant at Grangemouth would begin at the start of April.
OPIS also understands that multimillion-pound work to construct a combined heat and power (CHP) plant on the Grangemouth site has also been postponed.
"The new power station has been put back," a source told OPIS, referring to a plan to build a 350 million-pound project to replace the refinery's 40-year-old power plant. The source suggested that the current economic turmoil caused by the COVID-19 outbreak was responsible for the postponement.
OPIS revealed back in February 2019 that Ineos planned to start construction of the new plant in the fourth quarter of 2020.
Ineos did not respond to a request for comment by presstime.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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As it becomes more apparent that the impacts of coronavirus disease 2019 (COVID-19) on domestic and international travel could potentially go on for weeks, if not months, jet fuel traders and suppliers on the U.S. West Coast are working together to avoid supply lockups as storage tanks fill.
Los Angeles jet fuel prices are currently at 17-year lows around 71cts/gal.
Trade discounts are the deepest seen in years at 35.50cts below the NYMEX May ULSD futures.
"We're not at peak yet of this whole deal," said one West Coast jet trader.
"What do we do if we get to a full ground halt? These are all things we need to think about. Demand will get worse. You may see differentials fall to levels we haven't seen before."
LAX Fuels Consortium manages refueling of aircraft and required infrastructure in the Los Angeles region. LAX Fuels General Manager Enrique Gaytan said members are in discussions with suppliers to make adjustments and that "people are positioning themselves as best as possible."
"Everyone is taking a different approach, trying to iron out details and trying to catch up," Gaytan said. "We have seen a reduction in total volume. People are not taking full inventories."
The West Coast trader said it's likely most airlines have been proactively working with suppliers to prevent containment problems.
"Suppliers feel the pain just like we do," said one West Coast trader. "Cutting batches is not something we want to do."
Cutting batches may not be something air carriers want to do, but with the top five airlines at Los Angeles International Airport (LAX) recently announcing large reductions in capacity over the coming weeks, it's something they will all have to do.
American Airlines said March 10 that it will reduce international capacity by 10%, including a 55% reduction in transpacific capacity, and decrease domestic capacity by 7.5% in April. American Airlines flights accounted for 20.55% of passengers at LAX in January.
Delta Air Lines said March 10 that it would reduce international capacity by 20%-25% and decrease domestic capacity by 10%-15%. Delta flights made up 17.56% of the LAX market in January.
United Airlines said March 20 that it would reduce its international schedule by 95% for April, including a temporary suspension of all flights to Canada, effective April 1. United flights accounted for 13.50% of market share at LAX in January.
Southwest said March 16 that it would reduce available seat miles capacity by at least 20% from mid-April through early June. In January, Southwest Airlines flights made up 9.85% of the passenger share at LAX in January.
Alaska Airlines said March 10 that it would reduce April capacity by at least 10% and May by at least 15% from original expectations. Alaska Airlines flights made up 7.85% of LAX's January market.
"When you've got all the airlines (making cuts) you're not burning the fuel you normally would," a second West Coast jet fuel trader said. "The real story is the refiners. Where are they at? They are going to have to cut production."
OPIS has reported that Phillips 66 confirmed on March 24 that run cuts in its refining system are part of actions taken in response to the challenging business environment that has resulted from the outbreak and spread of COVID-19.
The energy company's refinery utilization rate of 90% previously given for first-quarter guidance is now looking more like a number in the low to mid-80s, said Jeff Dietert, head of investor relations, in a Tuesday conference call with equity analysts.
Phillips 66 characterized its exposure to COVID-19's especially harsh impact on jet fuel demand as a small issue. The company makes about 225,000 b/d of jet fuel, about half of which can be pushed into gasoline or distillate, Brian Mandell, executive vice president of marketing and commercial, said.
"We're left with a relatively small amount at most of our refineries," he said, adding that the company is working with airlines and others to take the jet fuel. "We don't feel that's a problem for us."
OPIS notes that the Phillips 66 Los Angeles refinery reportedly began reducing runs last week.
Marathon Petroleum Corp. began making production adjustments as well.
"MPC's refinery and marketing teams work together to continuously monitor market conditions and adjust our crude oil acquisition, refining run rates, logistics systems and marketing," a Marathon representative told OPIS via email. "As the unique market conditions associated with the extraordinary global effort to combat COVID-19 evolve, we are optimizing our system accordingly."
Marathon operates the largest West Coast refinery, a 363,000-b/d Los Angeles plant, as well as a 161,500-b/d refinery in Martinez, Calif., in Northern California.
Jet fuel inventory levels in California decreased by 1.5% for the week ended March 13, to 1.76 million bbl. Year-ago levels were closer to 2.3 million bbl, according to the California Energy Commission's Weekly Fuels Watch Report.
The OPIS West Coast Spot Market Report is the nation's premier price index for refined petroleum products.
Get a complete 5-day picture of the Los Angeles, San Francisco and Pacific Northwest refined spot markets plus West Coast crude oil postings, PADD 5 DOE inventory levels, feedstock values and more.
--Reporting by Bayan Raji, braji@opisnet.com; Kylee West, kwest@opisnet.com; and Beth Heinsohn, beheinsohn@opisnet.com;
--Editing by Lisa Street, lstreet@opisnet.com
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Chinese oil demand is set for a sharp recovery as more travel curbs are lifted, breathing new life into its beleaguered industries and retail sectors but is still a long way from achieving the same level of growth as seen in past years, industry sources said.
China will lift travel curbs on Hubei province, effective March 25 for areas outside Wuhan and from April 8 for Wuhan city, two-month after the lock down, according to local official announcement on Tuesday. Hubei and Wuhan were at the epicenter of the coronavirus pandemic (COVID-19) that is now sweeping the rest of the world.
Local media reported 203 new confirmed cases of COVID-19 on Tuesday, with 39% imported from overseas amid fears of a second wave of infections, which has led China to impose entry restrictions.
Total China oil demand loss was estimated to shrink to less than 1.5 million b/d and 0.5 million b/d, in March and April, respectively, as opposed to a massive 5.6 million b/d slump in February, or 40% compared to the same period last year, according to an estimate by IHS Markit in a March 18 report.
"China has, unlike most countries, definitively passed the nadir of the COVID-19 pandemic," said Sophie Fengli Shi, downstream associate director at IHS Markit in Beijing and one of the authors of the report.
"While oil demand outside of China is still in the midst of an unprecedented decline, consumption within the country is now firmly on the upswing."
Gasoline, which was one of the worst hit oil product at the peak of the COVID-19 outbreak, is expected to record a speedy recovery as traffic restrictions are lifted.
Highway traffic volumes rose by 13.24% on-year by mid-March, according to the Transportation Department, while oil sales by Chinese retail stations have recovered to above 80% of last year's level, IHS Markit data showed.
Its further growth, however, could be capped by a drop in automobile sales due to weaker consumer spending associated with economic slowdown, according to the IHS Markit report.
"We expect that the after effects of COVID-19 on the economy and on consumer behavior, including traveling activities and automobile purchases will linger for a long period of time, casting prolonged ripple effects on oil demand," the report said.
Jet fuel may be the slowest oil product to recover and is likely to be a drag on overall demand as more travel bans are imposed elsewhere in the world, sources said.
A similar pattern is expected as during the SARS outbreak where air traffic was slow to show signs of recovery due to the general public's "fear of flying" for a long period of time, according to the IHS Markit report.
"In our base case scenario, we expect that oil demand will be mostly brought back to last year's levels in the second quarter and some mild growth will be registered in the second half (although the growth will be down by approximately 200,000 b/d from our previous forecast)," according to the report.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Finland's Neste said on Monday that it would delay the scheduled turnaround at its refinery in Porvoo and would do only the most business-critical maintenance works planned for April- June.
The Government of Finland declared a state of emergency as of last week due to the coronavirus 2019 (COVID-19) outbreak.
The new schedule will be announced by the end of the third quarter of 2020, the company said, adding that the rest of the turnaround works are expected to be finalized in 2021.
The Porvoo complex has a refining capacity of 206,000 b/d or 12 million tons of petroleum products a year.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility. Tell Me More
-- Reporting by Nandita Lal, nlal@opisnet.com;
--Editing by Tim Wright, twright@opisnet.com
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Lufthansa has declared a force majeure on its supply contracts, a company representative told OPIS on Monday, while analysts believe that other airlines will follow suit.
A Lufthansa spokesperson on Monday told OPIS that the force majeure will be in place for the foreseeable future.
Lufthansa has cut 90% of its long-haul flights, and European short-haul flights have been reduced by 80%, the company said in a statement last week.
Finnair would not comment on force majeures, but the airline previously told OPIS that it has reduced its contractual fuel off-take.
A source close to another large European airline told OPIS on Monday that the company has minimized its jet fuel off-take.
"I don't think Lufthansa will be the only airline to issue a force majeure. It will be the case with some of the airlines that have a liquidity problem. They need to adjust expenses somewhere," Oliver Simkovic, an analyst at Raiffeisen, told OPIS on Monday.
All European airlines have reduced their flights in response to coronavirus disease 2019 (COVID-19), which has seen countries across the region impose travel bans and restrict freedom of movement.
In response, jet fuel prices in Europe have plummeted to historic lows, with OPIS on Friday pegging the jet barge differential at $72.75/mt below the April low-sulfur gasoil futures contract.
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--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Anthony Lane, alane@opisnet.com
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A lock down in India amid the coronavirus pandemic (COVID-19) could further dampen demand in the Asia LPG market, which is already languishing in unsold cargoes as the CP paper swap reached historic lows, days before Saudi Aramco sets its April CP, industry sources said.
India put traffic restrictions in over 75 districts across the country. Major cities such as the capital New Delhi, Mumbai, Bangalore, Chennai, Hyderabad and Kolkata have been placed under travel, work and movement restrictions until March 31, according to local media citing government officials.
Prior to the lock down, spot demand was already muted in March, with the latest tender heard back in early March by Indian Oil Corp (IOC) seeking two evenly-split full cargo for April delivery, and sources said they may eventually have only bought one cargo. However, this could not be confirmed.
India imported in 2019 a monthly average of 1.24 million mt of LPG, with 54% propane and 46% butane, based on IHS Markit's Global Trade Atlas (GTA).
Its LPG usage is highly concentrated in the residential and commercial sectors, approximately 91% of total demand, while China uses 60% in the same sector, followed by 25% as chemical feedstock and 11% for industrial uses as a fuel, based on IHS Markit data.
In China, when traffic controls were imposed for Hubei and other provinces across the country, LPG demand for residential, commercial and industrial use were the worst hit with a reduction by 700,000-800,000 mt in February, a 21% drop from January estimates, according to an IHS Markit special report on NGL titled "Unexpected black swan event impacting Chinese LPG market in the first quarter".
Its chemical uses, especially using propane as a feedstock for propane dehydrogenation (PDH) units, were less impacted due to a more comprehensive and longer value chain, said the report.
A same degree of reduction could translate to 260,400 mt or around six VLGC-sized cargoes of LPG demand loss for India, market sources said, which they said is to be expected and possibly even exceeded given India's skew toward the residential and commercial sectors.
Real-time LPG pricing helps you see how global markets fit together with the OPIS Global LPG Ticker.
Now you can track live the arbitrage relationships between key European and Asian spot LPG markets and the Mont Belvieu, TX, hub where OPIS holds the official industry pricing benchmark.
--Reporting by Lujia Wang, Lujia.Wang@ihsmarkit.com;
--Editing by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com
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Unprecedented demand destruction brought by the coronavirus disease 2019 (COVID-19) pandemic and a sharp increase in Saudi Arabia's exports is expected to continue to widen the contango structure in West Texas Intermediate futures, signaling that excess U.S. crude oil will now head into storage as the export window shuts.
As the front-month WTI contract has lost almost two-thirds of its value year to date, WTI's forward curve is turning deep in contango, when longer-dated futures trade at a premium to spot, encouraging participants to keep oil in storage and sell it for profits later in a record surplus market, analysts said.
On Friday, the one-year WTI premium between May 2020 and May 2021 climbed to nearly $10/bbl this week, a level last seen in early 2016, and the three-month May-August WTI spread widened toward $4/bbl.
Saudi Arabia's decision to relinquish its role as the supplier of last resort and join other producers in flooding the spot market with cheap heavy sour oil should put more pressure on Brent, making WTI unattractive for export, analysts said. They also expect the WTI-Brent discounts to turn into premiums, as U.S. refiners buy the cheaper heavier crude and as U.S. shale producers shut in production at lower prices.
Tank Tiger, a Princeton, New Jersey-based broker in the U.S., Caribbean and South American tank space and terminaling services, reported its busiest week since the company started business in 2015, with six times more customer activities than it has in a normal week.
"All of the storage that everyone wants is basically gone, and what's left isn't cheap anymore," said Tank Tiger CEO Ernie Barsamian, a 30-year veteran in the petroleum terminal business. While traders and users have already hoarded available tanks, Barsamian said that storage on a sub-lease basis is still available for the right price.
Andy Lipow, president of Houston-based consultant Lipow Oil Associates, said he expects to see keen interest in the biggest U.S. storage facilities such as the Cushing, Okla., storage hub, the LOOP underground caverns in Louisiana and the Pierce Junction storage facility in south Houston. "The crude oil market is oversupplied, and excess volumes are seeking storage locations," said Lipow.
Products in Contango Too; WTI at Premiums to Brent
On refined products, Lipow said he expects gasoline inventories are going to build due to social isolation as COVID-19 hits the U.S., and a contango will develop in New York Harbor, the delivery point of NYMEX RBOB futures, as stockpiles in the U.S. East Coast start rising.
The one-year contango spread for NYMEX RBOB between April 2020 and April 2021 widened to nearly 30cts/gal on Monday, a level last seen at the height of the 2008 global economic crisis, highlighting the historic drop in fuel demand.
Similarly, the one-year contango for NYMEX ultra-low-sulfur diesel has climbed to 20cts/gal, last occurring in 2016.
On Thursday, Colonial Pipeline Co. said it will slow fuel flows by 20% on its main route supplying refined products to the U.S. Northeast from U.S. Gulf Coast refiners, underscoring reduced downstream demand due to COVID-19.
Michael Tran, commodities strategist at RBC Capital Markets in New York, said the cost of storing a barrel at Cushing has doubled in the past several weeks, and floating storage costs on Very Large Crude Carriers (VLCC) have also risen significantly as Saudi Arabia chartered a number of VLCCs to move its crude for export.
Tran said higher tanker freight costs and the small WTI discounts to Brent at just over $3/bbl on Friday discourage U.S. crude export.
"Given the current pricing economics. We don't see exports as being economically viable at this point. We expect the U.S. crude exports are going to be quite tepid over the coming weeks," Tran said.
Sandy Fielden, director of oil and products research at Morningstar in Austin, Texas, said Brent's rapidly collapsing premiums to WTI at $1.74/gal on March 13 barely covered the pipeline shipping costs for WTI from Cushing to the U.S. Gulf Coast, let alone the freight costs to overseas markets, rendering WTI less competitive versus Brent from Saudi and Russian barrels in international markets.
"In effect, the narrow Brent premium traps WTI in the U.S. market," Fielden said.
Access live gasoline, diesel and jet fuel spot pricing throughout the trading day.
Easily predict where rack prices are headed with the OPIS Spot Ticker. This innovative tool is available online or via mobile app and displays real-time cash prices for all grades of gasoline, diesel, jet fuel and ethanol in all U.S. spot markets.
--Reporting by Frank Tang, ftang@opisnet.com;
--Editing by Denton Cinquegrana, dcinquegrana@opisnet.com
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Prices for California Carbon Allowances (CCAs), the primary compliance instrument in the state's Cap-and-Trade Program, have crashed more than $4/mt over the past three weeks and are now sitting below auction reserve prices, at multiyear lows.
The drop is tied to the broader economic and global market plunge in response to the global coronavirus disease 2019 (COVID-19) pandemic, but West Coast fuel suppliers say anticipation of lighter compliance obligations in 2020 may be playing a role as well.
California retail demand analysis by the OPIS DemandPro service showed an 8.4% decline in same-store fuel sales at West Coast retail stations for the week ending March 14, and stringent social distancing measures enacted in the state are expected to further quell fuel demand.
Gov. Gavin Newsom announced a shelter in place order for the state on Thursday to try to mitigate the spread of COVID-19.
Obligated parties under the Cap-and-Trade Program must surrender compliance instruments (either allowances or offsets) equal to their yearly emissions on a compliance schedule established by the California Air Resources Board (CARB).
Obligations for fuel suppliers are dependent on the amount and type of fuels they sell.
Traders at multiple major West Coast fuel suppliers told OPIS that they are closely considering the impact of reduced demand on their obligations.
Anticipation of reduced obligations are "why prices are getting killed," said one trader. "But it looks like they've dropped too far."
Another trader with a different supplier attributed the recent drop to lower demand leading to lower observations, as well as "risk off trader length."
The big unknown, they both agreed, is how long fuel demand remains crimped, which makes the most advantageous trading strategies at this time of extremely low allowance prices unclear.
"Some demand is still good right now, but other locations are already seeing 50% drop," said the first trader, and it's unknown whether these demand depressions will be "1-2 months" or "further out."
Cheap allowances are proving attractive to obligated parties looking at satisfying compliance obligations in future years.
Traders opinions were mixed on whether or not to jump into the fray to stock up on carbon allowances now, or to wait to see if prices will continue to fall, however.
Meanwhile, with secondary-market CCA prices trading well below the program's quarterly auction reserve price, there is a good chance that if that continues to be the case, the next auction, in May, could be undersubscribed, according to Clear Blue Markets analyst Nicolas Girod.
Traders agreed. "Who would bid the next auction if spot is trading $1 lower," the first trader said.
If the auction does not sell out, that reduces available allowance supply. In the long term, reduced supply could actually end up being bullish for prices, Girod noted.
For the time being, the currently reduced prices for CCAs are trickling down the fuel supply chain. The OPIS cap-at-the-rack (CAR) assessment, which estimates the impact of cap-and-trade compliance costs at the wholesale rack level, were 12.07cts/gal for CARB gasoline and 15.33cts/gal for CARB diesel on Thursday. Those prices were 14.36cts/gal and 18.25cts/gal, respectively, at the beginning of March.
Average California retail prices for regular gasoline were $3.25/gal Friday morning, down from $3.48/gal on March 1.
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--Reporting by Kylee West, kwest@opisnet.com, and Bridget Hunsucker, bhunsucker@opisnet.com;
--Editing by Lisa Street, lstreet@opisnet.com
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The head of the Renewable Fuels Association (RFA) is calling on Congress and the Trump administration to "act immediately to avoid a potential collapse" of the industry because of the coronavirus disease 2019 (COVID-19) pandemic.
In a conference call with reporters Thursday, RFA President and CEO Geoff Cooper said that even before the coronavirus began to "roil" the U.S. economy, the ethanol industry had experienced demand reductions and "challenging economics" because of the administration's expanded use of small refinery exemptions (SREs) from Renewable Fuel Standard (RFS) compliance, the loss of a major export market due to the U.S.-China trade dispute and the sharp decline in crude prices after OPEC and Russia failed to agree on production cuts.
"This is not just the perfect storm, it's the perfect tsunami," Cooper said.
Cooper, who was joined on the call by several CEOs of RFA member producers, said the trade group has received numerous reports of plants reducing or idling production in response to historically low prices.
OPIS on Monday assessed Chicago Argo ethanol, a key industry benchmark, at $1.075/gal, down 10.5cts from Friday to the lowest level since May 2003, when it was assessed at $1.06/gal. On Tuesday, OPIS marked Chicago Argo ethanol at 99cts/gal, a new record low.
"These are some of the worst margins we have ever seen in the ethanol industry," Cooper said. "To help our industry survive, we are calling on Congress to take action immediately to avert a potential collapse in the ethanol industry."
Cooper cited discussions in Washington about providing support to beleaguered U.S. oil and gas producers, including the administration's plan to buy oil for the Strategic Petroleum Reserve, and asked that aid also be provided to the renewable fuel producers.
He said the Trump administration should take the following steps to provide relief to the industry:
Cooper said the industry's top priority now is retaining its skilled workforce and saving jobs. "Every effort should be taken to do this, particularly given that many plants will have to temporarily suspend production."
Randy Doyal, CEO of Minnesota-based producer Al-Corn Clean Fuel, said he believes it "looks almost inevitable" plants will shut down in the near future.
"It is going to take a while for all of us to recover from the impacts of all of the shutdowns," Doyal said. "But at the same time, we are doing the best that we can to help our people."
Further, Doyal said he had not seen conditions in the industry this bad since the 2008-2009 Great Recession, adding that that was fairly short-lived. "This one I think we will feel for much longer than we want. We're trying to weather this storm as well as we can, but it's not going to be good."
Jeanne McCaherty, CEO of Guardian Energy Management, another Minnesota-based ethanol producer, said estimates that the coronavirus could reduce U.S. transportation fuel use by between 15% and 60% would result in "devastating demand" destruction for ethanol, adding that more producers have begun to come up against physical logistic constraints, chief of which is storage. "We and our customer have defined storage space and may have to shut down just for that. That's the first thing we look to and obviously the second thing is margin."
She said at an ethanol price of $1/gal or below, "no one in this industry is covering their variable costs. It is just not a viable option going forward."
RFA Chief Economist Scott Richman, who was also on the call, said it's "not just the magnitude in the downturn of fuel consumption, but also the duration of that downturn."
He added that ethanol prices at about $1/gal mean that most producers are "losing 25 cents on each gallon they produce. We're going through something that most of us have not experienced in our lifetimes."
Get accurate, up-to-the minute news, pricing and analysis for buying and supplying ethanol-blended fuel and biodiesel with OPIS Ethanol & Biodiesel Information Service. This service includes real-time news alerts, end-of-day pricing assessments, and a weekly newsletter and rack pricing report.
--Reporting by Patrick Newkumet, pnewkumet@opisnet.com;
--Editing by Jeffrey Barber, jbarber@opisnet.com
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Asian refiners outside China are planning run cuts and maintenance as a way of managing a collapse in global oil demand due to the spreading coronavirus 2019 (COVID-19) just as those on the mainland crank up crude throughput as the nation gets back on its feet.
Among refiners that are now considering cuts include Taiwan's CPC Corp. while others such as Shell in Singapore, SK Energy in South Korea and Trans Pacific Petrochemical Indotama (TPPI) have scheduled maintenance shutdowns, according to industry sources.
Taiwan:
CPC Corp. is considering a run cut by 5% at the 300,000 b/d Talin complex, although the reduction cannot be confirmed for now as the state-run refiner has refined product commitments in April to fulfill, according to the traders.
It does not have any plans for maintenance works in April and May.
Formosa Petrochemical (FPCC) already closed an 84,000 b/d residue fluid catalytic cracking (RFCC), a 180,000 b/d crude distillation unit (CDU) and an 85,000 b/d residue desulfurization unit (RDS) for maintenance works earlier this month, as reported earlier.
The works were expected to last until late April.
South Korea:
SK Energy plans to carry out turnaround at the No. 5 260,000 b/d CDU at its Ulsan complex in late May-late June period, industry sources said.
A company spokesperson declined to confirm the shutdown, saying they do not comment on maintenance works.
The nation's largest refiner has already cut runs at the 840,000 b/d complex by as much as 15% this month.
Hyundai Oilbank (HOB) will shut a 53,000 b/d fluid catalytic cracker (FCC) for scheduled turnaround at the same time as the No. 2 360,000 b/d CDU at the Daesan refinery, according to industry sources.
HOB is expected to shut the CDU from April 15 to May 7, while another CDU with 160,000 b/d capacity will stay on-line, as reported earlier.
During this period, it also plans to raise capacity of its residue desulfurization unit (RDS), according to the sources, although they declined to comment on how much the company will expand.
The country's smallest refiner by capacity has already cut runs by 10% since the end of 2019 and has been operating the two CDUs at 90% since then.
Japan:
JXTG Nippon Oil & Energy Corp. plans to take a 65,000 b/d CDU at the Kawasaki refinery off-line for about three months from mid-March to late June for scheduled turnaround, as reported earlier.
The other CDU at the site, with a capacity of 170,000 b/d, will remain running.
China:
Having survived COVID-19, China can now boast an improvement in its throughput by 700,000 b/d in March as the nation recovers, according to an IHS Markit report from the downstream team in Beijing. Refiners undertook the steepest throughput cuts of as much as 3.3 million b/d in February, a 26.5% reduction from a year earlier.
"With oil demand expected to contract for at least another month and with refineries' product tanks running almost full after a strong build throughout February, we see it necessary for refineries to extend their production cuts into March and April," they said in the report.
Run cuts in March and April were estimated to narrow to 2.6 million b/d and 1.3 million b/d, respectively, on a yearly basis under the base case scenario, the report showed.
China's oil demand declined by 5.6 million b/d in February, or 40% from the same period of last year. February was the worst month for Chinese oil consumption as cities and entire provinces were locked down to curb COVID-19 and also portends to what can be expected in some parts of the world where the virus is rampant.
Singapore:
Shell is set to shut a 210,000 b/d CDU at its 500,000 b/d Pulau Bukom refinery for scheduled turnaround from April 18, according to traders.
The works were expected to be completed by the end of May. Shell officials have not replied IHS Markit OPIS request for comment.
Indonesia:
Trans Pacific Petrochemical Indotama (TPPI) will conduct five-day maintenance in mid-April as planned, a company official said.
During the period, the company will shut its 50,000 b/d reformer and lower runs at its 100,000 b/d condensate splitter, the official said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Jongwoo Cheon, Jongwoo.Cheon@ihsmarkit.com, Thomas Cho, Thomas.Cho@ihsmarkit.com, Masayuki Kitano, Masayuki.Kitano@ihsmarkit.com, Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Sok Peng Chua, SokPeng.Chua@ihsmarkit.com
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Colonial Pipeline Co. will slow fuel flows by 20% on its main route supplying refined products to the U.S. Northeast from U.S. Gulf Coast refiners in response to reduced downstream demand due to the coronavirus disease (COVID-19) pandemic, the company said Thursday.
Colonial Pipeline said while it has been operating its pipelines at or near capacity and delivering on schedules in recent shipping cycles, the company realizes the impact of COVID-19 on demand and is taking proactive measures to help all shippers manage their inventory during this "unprecedented" situation.
"Based on input from shippers, our continued evaluation of the marketplace, and a thorough review of several options, Colonial will reduce flowrates on Lines 1 and 2 beginning next week. A reduction of approximately 20% in modified flowrates is currently targeted to begin Tuesday, March 24, 2020," the company said in a shipper bulletin Thursday afternoon.
The company, which operates 5,500 miles of pipelines between Houston and Linden, N.J., added that its plan is subject to change due to rapidly changing market dynamics.
OPIS notes that other product pipelines will likely follow suit, and refiners in the U.S. Gulf Coast will have to cut back production due to rapidly falling demand.
The move by Colonial signals demand destruction is starting to hit downstream, as fuel sales at some U.S. gas stations have dropped significantly in the last few days with most Americans telecommuting to work while staying at home to avoid social gatherings altogether, with the number of confirmed COVID-19 cases in the U.S. soared above 10,000 on Thursday.
Still, market sources said retail fuel sales remained surprisingly strong in parts of South Georgia and Alabama, but that's likely confined to only a few areas.
For Week ending March 14, year-on-year same store retail sales were down 2.4% for the entire U.S., according to OPIS Demand Pro service, which analyzes national retail fuel volumes.
Looking at regional arbitrage economics, the normal pricing relationship between U.S. Gulf Coast and New York Harbor CBOB gasoline markets inverted earlier this week, with Gulf Coast mogas costing a few pennies more than New York Harbor's, in contrast to NYH's typical few-cent premiums over those in USGC. The two markets were near parity on Thursday.
On ultra-low-sulfur diesel, New York continued to hold 5cts/gal plus premiums to the Houston markets over the last two weeks.
Line space on Colonial Pipeline's Line 1, which carries gasoline, saw values in the 1-2.65cts/gal discount to tariff range before this week, when values jumped to about even with pipeline costs. Line 2, which carries distillate material, has been 0.40-0.50cts/gal under tariffs for the last several sessions.
In New York Harbor, mogas cash prices regained some ground Thursday. However, this week has seen RBOB and jet fuel hit 18-year lows in the region, with ULSD around its lowest levels since 2016. With space on Line 3 - Colonial Pipeline's main refined products line between Greensboro, N.C., and Linden, N.J. - last valued around 0.10cts/gal above tariffs, there appears to be relatively limited interest in shipping barrels from the Southeast to the New York Harbor region.
OPIS DemandPro provides actual retail sales data collected directly from station operators. Gain the advantage in your market by knowing local gasoline sales volumes at all types of sites, including chains, new era marketers and branded retailers.
--Reporting by Frank Tang, ftang@opisnet.com, Rachel Stroud-Goodrich, rstroud-goodrich@opisnet.com, Cory Wilchek, cwilchek@opisnet.com, Denton Cinquegrana, dcinquegrana@opisnet.com, and Tom Kloza, tkloza@opisnet.com;
--Editing by Lisa Street, lstreet@opisnet.com
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Asia jet fuel cracks, or refining margins, have crumbled to their lowest levels in more than a decade even as refiners cut runs and tweak product slates in favor of gasoil while traders work to move overseas as many barrels as possible, industry sources said.
The scale of demand destruction triggered by a growing number of airlines that are canceling flights and even grounding entire fleets due to the spreading coronavirus disease (COVID-19) has sent jet fuel values plummeting and traders looking to even store barrels on board tankers despite the possibility of contamination, they said.
"Jet cracks are expected to remain under severe pressure in the second quarter and potentially falling to near zero. Airlines have announced capacity cuts of up of 90% as overseas travel comes to a halt with various restrictions and quarantine measures in place," said Matthew Chew, IHS Markit downstream principal analyst in Singapore.
Refiners will have to cut runs with no disposition outlets as export markets including the U.S. and Europe are also severely impacted as COVID-19 spreads rapidly in the West," he added.
The jet fuel crack has fallen to below $2.00/bbl, according to data from IHS Markit, which industry sources said was the lowest since at least 15 years.
At the same time, surplus cargoes in northeast Asia are sold at hefty discounts in order to force open arbitrage flows to Europe and the U.S. West Coast (USWC), traders said, with some pegging the differentials sinking to as much as minus $2-$2.50/bbl for supplies from China with South Korea barrels at just below this level.
This compares with differentials in the positive territory just a few months ago.
The arbitrage is working, even as freight rates increase, due in part to the wider jet fuel contango in the West and the bigger discounts traders are getting over in Asia, one trader said.
Shipping fixtures this week continue to show a slew of booking to both Europe and USWC. Petroineos chartered the STI Lobelia to pick up 90,000 mt from Yangpu for delivery to Singapore or Europe (UKC) at a cost of $1.3 million and $3.7 million, respectively.
Vitol chartered the Bryanston, also to load 90,000 mt but from South Korea for Europe at $3.5 million. This is the first long-haul April loading cargo booked, fixtures show.
The rates compare with that done for a similar LR1 cargo for loading in December from Yangpu at $2.9 million, a fixture list released on Dec. 3 showed.
On its part, PetroChina booked the MR tanker BW Bobcat to load a 35,000 mt cargo from Dalian on March 26 bound for USWC at a cost of $1.65 million, one fixture list showed.
Unlike in the West where companies have put tankers on short-term time charter to act as floating storage, such moves have yet to be mirrored in Asia.
There is a reluctance to put jet fuel on floaters as it is the most sensitive of all the oil products and has stringent specification requirements, industry sources said, adding that risks to contamination grow when it is kept on ships for months on end unlike crude oil or fuel oil.
However, there is the option for traders to slow steam the tanker and take advantage of the contango.
"The transit from North Asia to UKC is about 35 days and companies may park the vessel somewhere close to the eventual outlet. Naturally you have to ensure that the operations are good to minimize contamination," said one trader.
A fixture list released on Thursday showed that BP and Shell have taken an LR1 each in the West to store 60,000 mt of jet fuel. BP has the Stena Polaris booked for 45-90 days at $25,500 per day, and Shell the Torm Sara for 90-120 days at $35,000 per day, the list showed.
Jet fuel demand in Asia, and even around the globe, is crumbling fast as more and more airlines temporarily cancel flights and even shut up shop at the extreme.
Qantas and its budget carrier Jetstar will stop all international flights from the end of March and temporarily layoff two-third of their 30,000 staff. More than 150 aircraft will be grounded during this period.
Singapore Airlines announced a 50% cut to its scheduled capacity up to the end of April, while others such as Garuda Indonesia and Cathay Pacific have cut capacity by as much as 70% and 77%, respectively.
Jet fuel is buckling under these extreme pressures. Most players agree that a cut in production and severe dumping of the fuel into the gasoil pool, and even floaters if necessary, is needed to bring some stability to the market as the export outlets slowly evaporate, the sources said.
Reference a single daily index for buying and selling jet fuel and gasoil profitably in Asia with the OPIS Asia Jet Fuel & Gasoil Report.
--Reporting by Raj Rajendran, Rajendran.Ramasamy@ihsmarkit.com;
--Editing by Sok Peng Chua, SokPeng.Chua@ihsmarkit.com
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Unprecedented falling global demand due to the coronavirus disease 2019 (COVID-19) combined with Saudi Arabia relinquishing its role as the supplier of last resort is expected to increase global supply surplus to as high as 1.3 billion bbl in the first half of 2020, which would smash the previous record following the 2014-2015 oil price collapse, according to IHS Markit's crude oil research team.
"The world economy will eventually recover and oil demand will stop falling, but now and in the months ahead the scale of the world oil surplus -- the amount of supply above demand -- is of such a massive, unprecedented scale that governments will struggle to manage the damage it will cause to oil and related industries and to a world economy pummeled by COVID-19," IHS Markit said in its monthly global crude oil markets short-term outlook on Monday.
IHS Markit, a provider of critical information, analytics and expertise and the parent company of OPIS, said the report reflects its crude oil team's understanding and assumptions as of March 16, and the team expects to issue new updates reflecting the fast-changing market conditions very soon.
Monthly global oil demand from February through May 2020 will be as much as 4 million to 10 million b/d less than year-earlier levels, which would be the largest declines in oil demand in history, according to IHS Markit.
Immediate and steep production cuts and international collaboration could mitigate the damage. However, it is possible that Saudi Arabia is giving up its role as the balancer, as it is no longer willing to defend oil prices by cutting output only to see others increase theirs, IHS Markit said.
"No one can accurately predict a precise number, but the looming imbalance between demand and supply is so large that it is well beyond any typical margin of error or uncertainty about data," IHS Markit said.
According to IHS Markit, oil supply surplus in 1H 2020 will range from 770 million bbl to 1.3 billion bbl. Even at the low end of its forecast, the surplus is more than double the previous record of 320 million bbl in 1H 2015 after the 2014-2015 oil price collapse. "But even then, global oil demand was still increasing, not falling," IHS Markit said.
U.S. crude oil production by late 2021, hit hard by low oil prices, is expected to be 2 million to 4 million b/d below early 2020 levels, the report said.
IHS Markit's base case forecast projects a March-December 2020 average of $38/bbl for Brent crude futures. Most global oil production has operating costs of $20/bbl in Brent terms, it said.
President Donald Trump's plan to fill up the U.S. Strategic Petroleum Reserve could soak up 79 million bbl, or about 10% of the 1H 2020 global surplus projected in the base case. However, it is not clear what the intervention will be and when it will happen, according to IHS Markit.
"There will be government intervention to address collapsing sectors of the economy, but there is no historical precedent to guide such efforts amid such an enormous decline in demand. Global repercussions of the COVID-19 pandemic will be profound and cause ripples that are not yet visible or imagined," IHS Markit said.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Frank Tang, ftang@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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With jet fuel crack spread values at historic lows, aviation fuel is falling into the blending pools, European trading sources said.
Refining margins for jet fuel barges in and around the ports of Rotterdam slumped to historic lows of $2.75/bbl against Brent futures Tuesday, while ultra-low sulfur diesel barge cracks were pegged around $10.50/bbl.
"Diesel seems pretty lucrative at the moment, there is healthy demand. Airports are now closed, so everyone will drive," one source active on the jet market said.
Some airlines, such as Ryanair, have cut their flight schedules for April and May by 80%. Meanwhile, some of the largest economies in Europe -- Spain, France and Germany -- have closed their borders.
Energy forecaster JBC Energy said in its latest note to the market that the restrictions on air travel in and around Europe mean jet fuel demand there is seen declining by at least 70% (1 million b/d) over March-April compared with that of last year.
A source from the diesel market said diesel buyers are looking to fill up storage.
"People have booked caverns, so these are slowly filling up. We are swimming in diesel, but so far not all tanks have been filled," the diesel source said.
Data from consultancy Insights Global last week showed that at 1.922 million tons, gasoil stocks in Europe were 32.6% below five-year-average.
However, travel restrictions are also likely to start weighing on diesel demand. "Europe is already swimming in diesel, and most people will only travel to shops so we'll see the demand drop off soon," the diesel source noted.
GAIN RELIABLE JET FUEL CONTRACT PRICING WITH ALL-DAY TRADE VISIBILITY.
Using a live trading platform, the OPIS450 Europe Jet Ticker converts bids, offers and deals in the barge jet fuel market into a price mark for each minute between 9:00 a.m. and 4:30 p.m. London time. The average of those 450 prices creates a value for the entire trading day, providing carriers and suppliers with an accurate and impartial market assessment. Combine the all-day visibility of the Ticker with the expert market commentary found in the OPIS450 Europe Jet Fuel Report and you have a complete and transparent picture of each day's entire activity.
--Reporting by Selene Law, selene.law@opisnet.com;
--Editing by Paddy Gourlay, patrick.gourlay@ihsmarkit.com
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Hearings originally scheduled for next week to address Saskatchewan and Ontario's legal challenges to Canada's federal carbon backstop pricing program have been tentatively rescheduled to June 2020, according to a statement from the Chief Justice of Canada this week.
The Canadian government last year instituted the output-based pricing system (OBPS) -- a greenhouse gas tax commonly called the "backstop" plan -- on provinces without federally approved carbon pricing programs in place. As of Jan. 1, 2020, the federal fuel charge was in effect in Ontario, New Brunswick, Manitoba, Saskatchewan and Alberta.
"The Supreme Court of Canada is closely monitoring the advice of public health officials with respect to COVID-19 and is working with various stakeholders in the justice system to address the issues arising out of this exceptional situation," the Chief Justice's statement said.
The hearings scheduled on March 24, 25 and 26 for the cases Attorney General of Saskatchewan v. Attorney General of Canada and Attorney General of Ontario v. Attorney General of Canada, along with an unrelated case scheduled for the same days, are being rescheduled "in order to protect participants in the justice system and to reduce the spread of COVID-19," it said.
The delayed hearings are part of the appeals process following appellate court decisions in Saskatchewan and Ontario last year that examined provincial challenges to the federal backstop plan and found it constitutional.
Meanwhile, a separate provincial court of appeals last month found the federal pricing backstop plan unconstitutional in a 4-1 decision based on a similar legal challenge from Alberta. Federal Environment Minister Jonathan Wilkinson said at that time that he looked forward to the constitutionality of the program being ultimately adjudicated by the Supreme Court.
Easily track and manage carbon compliance costs to your business.
Ever-evolving climate change policies impose a growing influence on traditional fuel markets and carbon credit markets can be extremely volatile. Easily track and manage carbon compliance costs to your business with the OPIS Carbon Market Report.
--Reporting by Kylee West, kwest@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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The outlook for U.S. refining operations amid the price wreckage of wholesale and futures markets is gloomy amid indications of sizeable, if not massive, declines in demand for transportation fuels as a result of coronavirus disease 2019 (COVID-19) sweeping economic impacts.
Oil market participants were greeted today by U.S. wholesale gasoline prices trading at or below the price of crude oil which results in narrow to nonexistent crack spreads. Take gasoline, for example. At settlement, West Texas Intermediate (WTI) futures were $28.70/bbl and RBOB futures were valued at 68.99cts/gal, or $28.98/bbl. Brent crude futures closed at $30.05/bbl.
Accounting for the cost to process crude oil into fuels (no less than $2.50/bbl) and the current 5-8cts/gal discounts commanded for very prompt gasoline in bulk markets around the U.S. deepens the unprofitability of the fuel.
Ultra-low-sulfur diesel (ULSD) prices continue to hold up better than gasoline (April futures settled at $1.0466/gal) and have lent support to the much-watched WTI 3-2-1 crack spread ($5.27/bbl based on today's settlements), but the unprecedented demand destruction seen for gasoline, jet fuel and diesel has fuel market participants and analysts alike expecting refinery run cuts as inevitable.
No refinery curtailments have been announced but market participants say the potential exists for temporary closures of some smaller plants or small-percentage run cuts across some companies' multi-refinery systems.
Alternatively, refiners who have had major processing units down for planned maintenance are seen likely to extend or deepen that work rather than restart them and run them at a loss. Also possible are deferments of upcoming maintenance, made to stem the outflow of cash on hand.
The RBOB crack spread - which in early March was solid at $17/bbl - "will crash so hard in the next week or two that it can't not impact" gasoline production, Debnil Chowdhury, IHS Markit Executive Director, North American Refining & Marketing, told OPIS.
Smaller, less-complex refineries will have to reduce output (or shut) first and then there will be cuts by the larger refineries, he said, likely for a period of months.
IHS Markit -- the parent company of OPIS - is in the process of modelling refined product demand impacts from COVID-19 and has seen indications that suggest "giant" reductions, Chowdhury said.
The reduction of rush-hour traffic in North America in the wake of widespread workplace, school, commerce and entertainment shutdowns to contain and mitigate the spread of COVID-19 is down 30% to 40% in numerous major metropolitan regions, pointing toward a "massive decline in gasoline demand," he said.
Vehicle miles traveled, the U.S. Department of Transportation's measure of road travel, support that view, with data showing that VMT are off by half if not a little more, Chowdhury added.
VMT data are likely also to reflect some short-term artificial upside for diesel demand, he said, due to goods "distribution centers going crazy resupplying" grocery and big-box stores that are seeing panic-buying and hoarding by consumers worried about quarantine and travel restrictions.
However, when the COVID-19 virus causes more Americans to be bedridden and/or housebound that shopping upside for diesel is likely to peter out. In addition, shipping companies' preference for very-low-sulfur fuel oil (VLSFO) amid decreasing ship movements has hurt demand for diesel, according to Chowdhury.
He also sees a reversal in a distillate market dynamic that was in play just before and after the International Maritime Organization (IMO) low-sulfur fuel rules went into place Jan. 1.
Before COVID-19, the price of "diesel was strong due to IMO 2020, and diesel was pulling jet fuel (prices) up with it," he said. "Now, we think the jet crack gets so bad that it pulls diesel down with it."
Demand for jet fuel - clearly falling after weeks of piecemeal route cancellations - will see additional declines as a result of the Trump administration's halt to Europeans traveling to the U.S., Chowdhury said, of 300,000-350,000 b/d in both the U.S. and in Europe.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Denton Cinquegrana, dcinquegrana@opisnet.com
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European jet cargo differentials versus European distillate futures have sunk to historical lows Monday amid the coronavirus disease 2019 (COVID-19) pandemic in Europe.
Shell sold a 30,000-ton jet cargo to BP at a $12/metric ton discount to April low-sulfur gasoil (LSG) futures on the ICE bourse, according to data from brokers.
The cargo, which is onboard the vessel Abu Dhabi III, will be delivered to the port of Rotterdam between March 30 and April 3.
"I have never seen jet cargo differential this low. There must be a bottom somewhere, but I don't know where it will be," one jet broker told OPIS. Excluding today, jet cargo differentials in northwest Europe have averaged $30.25/ton above front-month low-sulfur gasoil futures since the beginning of the year, according to OPIS data.
Most European airlines cut their flight schedules this weekend, shaving up to 90% of the flights, as European countries are closing their borders in a bid to stop the spread of the COVID-19 coronavirus.
GAIN RELIABLE JET FUEL CONTRACT PRICING WITH ALL-DAY TRADE VISIBILITY.
Using a live trading platform, the OPIS450 Europe Jet Ticker converts bids, offers and deals in the barge jet fuel market into a price mark for each minute between 9:00 a.m. and 4:30 p.m. London time. The average of those 450 prices creates a value for the entire trading day, providing carriers and suppliers with an accurate and impartial market assessment. Combine the all-day visibility of the Ticker with the expert market commentary found in the OPIS450 Europe Jet Fuel Report and you have a complete and transparent picture of each day's entire activity.
--Reporting by Selene Law, selene.law@ihsmarkit.com;
--Editing by Paddy Gourlay, patrick.gourlay@ihsmarkit.com
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Gasoline prices in all three West Coast spot markets have crashed around 70cts/gal since the start of March, and in the past week alone, prices have slashed around 40cts/gal.
Los Angeles and San Francisco CARBOB as well as Pacific Northwest sub-octane spot prices were under $1/gal Friday afternoon.
Plunges in the futures market, which underpins spot prices, have been the motivating factor, dragging prices lower amid demand concerns tied to coronavirus disease 2019 (COVID-19) and an oil price war between Saudi Arabia and Russia.
West Coast spot prices are touching on lows not seen since 2016, which at that time were also futures-led. The oil market staged a relatively quick recovery by April from February low-water marks that year, but recovery from the current depths may be more drawn out, given increased social distancing measures being put into place each day to prevent the spread of COVID-19, in turn dampening demand.
Futures differentials on the West Coast have put up little to no resistance to basis weakness, leaving spot prices at the mercy of steep losses in underlying paper trade.
In California, supply fundamentals aren't doing much to support prices either.
There's a handful of planned and unplanned maintenance underway in both Southern California and the Bay Area, but regional supply fundamentals show healthy inventory levels. Both production and stockpiles of CARB gasoline were up in both weekly and annual comparisons in this week's Fuels Watch Report from the California Energy Commission.
"I think ultimately the West Coast refiners will respond via run cuts and exports to the eventual demand shock that's coming," said one veteran trader.
Pacific Northwest gasoline appeared well-stocked too, placing overall pressure on cash differentials, although day-to-day volatility has been observed as the region continues to move through its spring RVP transition. Sources told OPIS that the arrival of the vessel Gulf Rastaq, laden with a cargo of sub-octane, is likely to exert a bearish impact on futures differentials.
The Gulf Rastaq was in the northern Pacific Ocean Friday, indicating an arrival in Portland on Saturday, according to ship tracking data from Market Intelligence Network (MINT) by IHS Markit.
IHS Markit is the parent company of OPIS.
Distillate prices on the West Coast hit four-year lows as well this week, although losses were closer to 50cts/gal since the beginning of the month, reflective of a bit more resilience in ULSD futures than RBOB overall the past two weeks.
Spot market participants expressed to OPIS that they aren't expecting demand depression, and its impact on fuel prices, to let up anytime soon, noting weakening of cash differentials for non-prompt month April delivered barrels that accelerated on Friday.
"I think everyone is anticipating gasoline demand to crater," said a second veteran trader.
The OPIS West Coast Spot Market Report is the nation's premier price index for refined petroleum products. Get a complete 5-day picture of the Los Angeles, San Francisco and Pacific Northwest refined spot markets plus West Coast crude oil postings, PADD 5 DOE inventory levels, feedstock values and more.
--Reporting by Kylee West, kwest@opisnet.com, Bayan Raji, braji@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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MEXICO CITY - The conditions surrounding the current oil price crash is unique and unprecedented in over 90 years, Mexico's former Deputy Hydrocarbon Secretary Aldo Flores told OPIS.
"We are in a delicate and uncommon situation of a simultaneous demand and supply shock," Flores said. "The last time something like this happened at such an extreme was perhaps in (the 1930s) Great Depression."
Flores said that at the time, global demand for commodities, including oil, tanked, just as production from Texas and Oklahoma boomed, causing a price collapse.
This was when the Texas Railroad Commission stepped in to dictate production quotas, a move that later inspired the creation of OPEC, Flores added.
In comparison, the fallout from the 2008 financial crisis, with a demand drop and excess supply, bears some resemblance, but it was brief as prices went up within a year, he added.
"Today, we are witnessing a conscious effort to increase supply amidst a sharp demand decline," Flores said.
"The price war Russia and Saudi Arabia have is hardly in anyone's best interest," he added.
Low prices will discourage investment in an industry that requires a sustained effort to bring production to the market every year, he said.
Price War Jeopardizes Future Supply Stability
"Today's investment delays might result in insufficient supply when demand picks up again," he added.
A sizable share of the world's current production depends on higher oil prices as it is financed with debt.
"This situation in one hit puts at risk not only unconventional production but also high-cost conventional projects," Flores said.
"Tracking the debt rollover from shale producers will be critical as a good portion of their supply depends on sustained financing, something challenging due to the difficulties the sector has generating returns," Flores said.
There is speculation that the U.S. government will support shale producers as the oil sector has become an important engine of the country's economy in recent years, he added.
It is difficult to know how long the price war will last, but the quick resolution does not appear to be on the horizon.
"If the communication channels remain open, there will be a space for Russia and Saudi Arabia to continue speaking and come to a resolution," Flores said.
However, if both parties remain immovable from their standing regarding an output cut, it will not be very easy for the situation to resolve soon.
"Saudis and Russians appear committed to waiting until someone blinks," he added.
A change in position will not be easy in the immediate term but does not appear impossible, said Flores, who also is the former Secretary General of the International Energy Forum based in Riyadh, Saudi Arabia.
Mexico has been caught in a difficult position by this low-price environment.
"The country needs significant investments to reach the production levels every administration has aspired to since 2004," he added.
Currently, the administration of President Andres Manuel Lopez Obrador has set a goal of producing 2.4 million b/d by 2024, an increase of 600,000 b/d from current output.
Mexico faces the challenge of replacing 70% of its current production, which comes from 24 mature and declining areas such as Ku-Maloob-Zaap that are projected to deplete over the next decade, data from the Mexican government revealed.
Mexico Could Play Mediator Role
The administration could retake the international leadership role Mexico has played in the past to build a constructive dialogue among producers and consumers during difficult times, Flores said.
Mexico played a pivotal role in bringing parties to a resolution during the Venezuela-Saudi Arabia price war in 1998.
Mexican Finance Secretary Arturo Herrero said Tuesday that is willing to help mediate on the situation between Russia and Saudi Arabia without giving further details.
"We, along with some other countries, are looking to be a type of third party to build bridges," Herrera said at a press conference.
Energy Secretary Rocio Nahle said Wednesday that Mexico is willing to adjust a share of its output to avoid a crude overproduction, adding that Mexico remains in permanent communication with OPEC members.
Over recent years, the relationship between Saudi Arabia and Russia was constructive but a challenging one from the point of view of their different energy policies and industry models.
"Russia doesn't have a national oil company but a more hybrid oil sector.
Declaring oil output cuts can be difficult in this situation," Flores said.
"For Saudi Arabia, it is also difficult being OPEC's only swing producer and requiring the cooperation of other members."
"Sustaining cooperation under these two limitations was already difficult under any scenario (for both nations)," said Flores, who participated in the OPEC+ meetings in 2016.
Bleak Future for Refined Products
The panorama for refined products seems weak. In 2018, the International Energy Agency projected a start-up of 7 million b/d of new capacity by 2022-2023; meanwhile, demand would increase of 5 million b/d, Flores said.
The COVID-19 coronavirus pandemic will hurt demand growth, he added. All international and government agencies have cut their oil demand growth forecasts.
The U.S. Energy Information Administration has slashed its global oil demand growth to just 370,000 b/d rather than 1.3 million b/d up from 2019 levels.
OPEC and the IEA expect close to no increase in demand for 2020.
"If all the capacity expected to come online materializes, there will be excess supply and thinner margins. Refining companies will have to be very disciplined in their operations," Flores said.
OPIS RESOURCES FOR MEXICO’S FUEL MARKETS
Fuel price transparency, news & training to help you successfully navigate Mexico's changing fuel markets.
--Reporting by Daniel Rodriguez, drodriguez@opisnet.com;
--Editing by Justin Schneewind, jschneewind@opisnet.com
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Asian petrochemical producers may consume less liquefied petroleum gas (LPG) than originally planned in the coming months as cracking economics shift in favor towards naphtha, market sources said .
Crude prices plummeted by over 30% on Monday to their low-$30s/bbl, a level last seen four years ago following a breakdown in talks between OPEC and key ally Russia on output cuts.
The CFR Japan naphtha price shed 23.7% on the same day to $311.500/mt, far outpacing the 15% fall in the CFR Japan propane price at $327.50/mt. The prices are their lowest since Feb. 24, 2016 and Sept. 16, 2016 respectively.
"Naphtha prices are so depressed now because of the low crude oil prices so there will be more naphtha cracking," said Matthew Chew, principal researcher at IHS Markit in Singapore.
Asian crackers had indicated they preferred to use LPG over naphtha prior to the crude price collapse on Monday. According to the monthly IHS Markit OPIS cracking survey completed on March 6, 17 companies across Asia had planned to crack 561,000 mt of LPG in April, up 6.9% from March.
But with LPG prices now higher than propane, Asian crackers are mulling changes to their feedstock slates.
"Naphtha looks more economical than LPG right now as the propane/naphtha ratio is high," said a senior feedstock procurement official at a Northeast Asian petrochemical company that had participated in the cracking survey.
IHS Markit OPIS calculates the propane/naphtha ratio by comparing the second physical trading cycle for CFR Japan propane against the first trading cycle for CFR Japan naphtha.
Petrochemical producers typically find it more attractive to crack LPG instead of naphtha when the ratio dips below 0.90. The ratio surged to 1.039 on Monday, the highest since Oct. 30 2017, IHS Markit OPIS data showed.
Refining crude oil produces both naphtha and LPG. But Asian propane prices found some recent support from propane dehydrogenation plant (PDH) operators in China, where the coronavirus disease 2019 (COVID-19) outbreak appeared to be easing after having ground the country's economic activity to a near standstill.
PDH plants use propane exclusively as feedstock.
Cracker operators meanwhile have been cutting run rates in face of weak downstream demand. Taiwanese private sector refiner Formosa Petrochemical Corp (FPCC) reduced the average run rates of its three naphtha crackers in Mailiao to around 90% from March, down from around 99% to 100% in January and February respectively, a company official said.
South Korea's LG Chem reduced run rates at its crackers in Daesan and Yeosu from March 1, while YNCC is planning to cut the run rate for its No.2 cracker in Yeosu for 2-3 weeks, according to IHS Markit's Asia Light Olefins Weekly published on March 6. Fellow South Korean petrochemical producer shut a 1.1 million mt/year cracker after an explosion on March 4.
Japan's Maruzen Petrochemical and Keiyo Ethylene were due to cut run rates in March, while Mitsui Chemicals reduced run rates in late February, according to industry sources.
"The probability of downside risk for petrochemical products, which already have been impacted by COVID-19, has increased further after the plunge in oil prices," IHS Markit said in a report on March 10.
The Caixin headline manufacturing PMI for mainland China, compiled by HIS Markit, dropped from 51.1 in January to 40.3 in February, the sharpest deterioration since the survey started almost 16 years ago, Bernard Aw, principal economist for IHS Markit said in a PMI commentary on March 2.
Methodology: IHS Markit OPIS collects Asian petrochemical companies' plans for the current month and the next month, as well as actual cracking volume in the previous month. IHS Markit OPIS checks if any manufacturers revise their plans for the current month and if any manufacturers crack more or less than initial plans in the previous month. IHS Markit OPIS contacts feedstock procurement officers of each companies for the survey by phone, email or messengers in the last week of previous month or the first week of the current month.
Gain greater transparency into Asia-Pacific markets for more strategic buy and sell decisions on refinery feedstocks, LPG and gasoline with the OPIS Asia Naphtha & LPG Report.
--Reporting by Jongwoo Cheon Jongwoo.Cheon@ihsmarkit.com, Masayuki Kitano Masayuki.Kitano@ihsmarkit.com, Lujia Wang Lujia.Wang@ihsmarkit.com,
--Editing by Hanwei Wu, Hanwei.Wu@ihsmarkit.com
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OPEC's monthly report has joined other analyses in slashing its forecast for global oil demand and warns that Russia's economy will take a big hit if crude prices do not bounce back.
OPEC's March report lops off 1 million b/d in global demand from last month's 100.73-million-b/d forecast.
"Total global oil demand is now assumed at 99.73 million b/d in 2020," said OPEC. "Considering the latest developments, downward risks currently outweigh any positive indicators and suggest further likely downward revisions in oil demand growth," it said, referring to the spread of the coronavirus disease 2019 (COVID-19).
OPEC's February report had already revised down its forecast for total demand growth in 2020 by 230,000 b/d because of the virus outbreak. That forecast represented global oil demand growth of 0.99 million b/d.
The March report also downgrades the demand call on OPEC supply in 2020 by 1.1 million b/d.
"Demand for OPEC crude in 2019 stood at 29.9 million b/d, 1.2 million b/d lower than the 2018 level. Demand for OPEC crude in 2020 is expected at 28.2 million b/d, around 1.7 million b/d lower than the 2019 level," the March report states. Quoting secondary sources, the report said that OPEC production "dropped by 546,000-b/d month-on-month to average 27.77 million b/d" in February.
Output dropped partly because of blockades to supply out of Libyan ports by a local commander opposed to the current government. Saudi production in February was also down month-on-month by 56,000-b/d to 9.68 million b/d.
The report barely refers to the Monday's dramatic falls in crude prices and the apparent end of OPEC's three-year pact with Russia to guide crude prices.
However, the report's forecast for Russian economic growth made clear the potential damage of a crude price war.
"Russia's current national reserves, and relatively low inflation levels as well as lower dependency on imports, may help mitigate some of the effects implicated by lower oil prices," said the OPEC report.
"However, ongoing declining oil prices may negatively and directly affect per capita real income. The government might be forced to postpone the large investments it has been planning for the massive national projects requested by the government. It is estimated that a continued decline in crude oil prices may lead to a drop in Russia's economic growth of as much as 0.5 percentage points in 2020," it concluded.
The report leaves OPEC's forecast for Russian crude output in 2020 virtually unchanged on its February prediction at 11.52 million b/d, up from 11.44 million b/d in 2019.
Russia threatened this week to increase output by 500,000 b/d from current levels to 11.8 million b/d in response to Saudi Aramco pledging to boost its production to 12.3 million b/d.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Anthony Lane, alane@opisnet.com;
--Editing by Paddy Gourlay, pgourlay@opisnet.com
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Saudi Arabia's national shipping carrier Bahri has placed at least 15 and up to 30 very large crude carriers (VLCCS) on subjects to ship crude oil with loading from as early as Mar. 20, shipbrokers said.
At least seven of these tankers are currently expected to head to either the US Gulf or east Asia. The Dalian, Agios Fanouris I, Hong Kong Spirit, DHT Panther, Maran Thaleia, Maran Canopus and the Maran Arcturus are currently being booked to load crude from Saudi Arabia during Mar 20 to Mar 31 at rates of between WS42.5 to WS57.5 to head to the US Gulf.
Bahri also placed options on the Maran Thaleia, Maran Canopus and the DHT Panther to head to east Asia at around WS85.
Another three VLCCs, the Front Kathrine, the Boston and the Agios Sotis I, are booked to move crude from Ras Tanura to the Red Sea. Bahri placed another five VLCCs--- the Newton, Dlama, Asia Dawn, Hojo and Alsace-- on subjects for cost of affreightment (COA) assignments from March 20.
Fixtures for tankers placed on subjects might still be cancelled subsequently.
But it is still unusual for Bahri to place so many tankers on subjects within such a short space of time, shipbrokers said.
This is likely related to Saudi Arabia's plan to raise crude output to 12.3 million b/d in April, an increase of more than 25% from February, market sources said. Buyers in Asia and the US Gulf are expected to be among the main recipients of this increase in crude output.
Bahri's unexpected booking spree drove VLCC freight rates sharply higher, shipbrokers said. According to the Baltic Exchange, the freight rate for the Middle East to US Gulf route rose by 18.96 points from the previous day to
WS52.41 on March 10. The freight rate for the Middle East to Singapore route rose by 22.42 points to WS78.42 while that for the Middle East to China route rose by 21.84 points to WS78.42.
All three rates are at their highest in more than a month.
The slew of fixtures portends an increase in crude oil flows from the Middle East to Asia. But it is unclear exactly how Asian refiners are going to absorb this inflow and for how long.
"The reduction of Aramco prices for April loading is definitely a great opportunity for the refiners to boost their margins but it could be short-lived, " said IHS Markit executive director Premasish Das.
With global demand for refined products expected to decline this year, refiners would not be able to process more crude if there is no demand support.
"Refiners will maximize their crude purchase at a discounted price, subject to their storage capacities, and process more crude oil before market fundamentals counter it," Das added.
Amid the weak demand outlook, several trading firms and majors in Asia have also been seeking VLCCs to use as floating storage, as reported by OPIS earlier.
TRACKING COMMODITY CARGOES HAS NEVER BEEN EASIER.
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--Reporting by OPIS Asia team
--Editing by Hanwei Wu, Hanwei.wu@ihsmarkit.com
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MEXICO CITY -- Pemex cut its regular gasoline 87 rack posted prices by peso 0.75/liter (4.23%) nationwide to peso 17.15/liter on Tuesday.
Pemex's rack posting on Tuesday for regular gasoline at the 18 de Marzo terminal in Mexico City was peso 17.48/liter, down 3.6% from peso 18.13/liter the previous day.
The cut in Pemex's posted rack prices follows the historic crude oil price crash reported yesterday, when May Brent fell to $34.36/bbl and April WTI settled at $31.13/bbl, down $10.15/bbl for the day.
OPIS on Monday assessed the spot price of regular gasoline landed in East Coast Mexico from the U.S. Gulf Coast at peso 5.586/liter, a drop of peso 1.43/liter, or 20.3% less compared with Friday.
According to OPIS Mexico Racks, the average retail price for regular gasoline nationwide across the country was peso 19.450/liter, unchanged from the prices reported yesterday.
Mexico's retail prices have been slow to pass savings from the drop experienced in the international market to end consumers. Regular gasoline prices have fallen only peso 0.5/liter since Feb. 2, when Mexico stopped subsidizing fuel prices.
Including the entire 4.95 IEPS tax, plus the CO2 tax, freight and VAT, east coast Mexico spot landed regular gasoline prices have fallen close to peso 2.2/liter from Feb. 2 to peso 12.37/liter on Monday.
OPIS Mexico RacksAs price liberalization expands in Mexico, rely on OPIS for daily implied wholesale prices at terminals across the country.
--Reporting by Daniel Rodriguez, drodriguez@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
Copyright, Oil Price Information Service
Monday's plummet of marine bunker fuel prices was met with cautious optimism Tuesday, noting cheaper fuel is welcome, but shippers might also need a freight rate bump to cash in on inexpensive fuel.
One of the main issues when [bunker] prices fall, freight rates go down with them," said one buyer from an American shipping company. "Now if you can load your tanks, and the market turns around and rates go up, you are in a good position."
On Monday, OPIS assessed 0.5%S (very-low-sulfur fuel oil) FOB Houston $70 per metric ton lower to $315 per metric ton ex-wharf, down by 18.2%. At the same time, bulk VLSFO was assessed $74.86/mt ($11.17/bbl) lower to $287.25/mt ($42.86/bbl), a decrease of 20.7%. May Brent crude on Monday fell $10.91/bbl to $34.36/bbl, a drop of 24.1%.
VLSFO averaged $566.57/mt in January and $470.63/mt in February, according to OPIS data. VLSFO for March was currently averaging at $404.42/mt over the course of six assessment days.
Another bunker buyer added: "You can rightly speculate we are at a [bunker price] bottom right now, so it would make sense to jump in and buy what you can, where you can buy it ... otherwise, you wait to buy and the fuel is gone. Why wait to buy?"
The current market situation is a result of several moving parts that includes a global demand slowdown resultant of the forceful punch of the coronavirus disease (COVID-19) that was followed by the failure of OPEC+ to agree on production cuts and Saudi Arabia possibly ramping up production to perhaps as much as 12 million b/d from slightly less than 10 million b/d. Crude values crashed and the products markets followed, hence low-priced bunker fuel.
MONITOR KEY BUNKER FUEL PRICES AND RELATED GLOBAL SHIPPING MARKETS.
OPIS Global Marine Fuels Report delivers daily assessments of marine bulk and bunker fuel prices in key global ports, including calculated prices for the new 0.5% VLSFO, a new fuel created in anticipation for IMO 2020. Easily track cargo and bulk fuel prices for Asia, Mideast, Europe and the Americas with this concise report filled with at-a-glance tables and charts.
--Reporting by Tom Sosnowski, thomas.sosnowski@ihsmarkit.com;
--Editing by Eric Wieser, eric.wieser@ihsmarkit.com
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2020 arrived with nearly all markets across the country finding rack gasoline above $1.50/gal and in some West Coast markets, above $2/gal. However, thanks to yesterday's unprecedented drops in spot markets, and perhaps due to pessimism among refiners looking to sell their gasoline production, OPIS has confirmed dozens of rack prices for E10 today at less than $1/gal.
The cheap prices are in many cases the result of aggressive discounts off OPIS Low postings, but there are an equal amount of areas where refiners have simply cut prices in order to clear inventory.
Moving from west to east, the first distressed market one comes across is Denver, which has occasionally found the cheapest wholesale availability since February. E10 was available at the Denver unbranded rack today for just 93.50cts/gal thanks to a 5.69ct/gal discount to the OPIS Low. Other Colorado locations were prone to price weakness with sales prices in the $1.03/gal range.
A cluster of very cheap gasoline prices was apparent in states that included Illinois, Indiana, Ohio and Michigan. Indianapolis, Ind., E10 was available today for just 93.3cts/gal and Huntington, Ind., had the same number with Hammond about 0.3cts/gal higher. In Illinois, OPIS confirmed E10 availability for less than $1/gallon in Decatur, Heyworth, Robinson and Rockford.
Michigan was likewise compromised by the cheapest wholesale gasoline since 2016 with Detroit, Ferrysburg, Jackson, Marshall, Muskegon and Niles in the 90s.
Ohio refiners had similar challenges with E10 breaking below the $1/gallon mark in Cleveland, Columbus, Dayton, Lorain and Toledo.
St. Louis area marketers could lift gasoline in Wood River for just 95.5cts/gal thanks to a 13.9cts/gal discount off OPIS Low and Jefferson City in that state saw a net 97.75ct/gal price thanks to a discount of 12.25cts/gal.
Also joining the sub-$1/gallon parade were points in Oklahoma, Wisconsin and Wyoming.
In almost all cases, the aggressive rack prices are well below what spot replacement costs for CBOB and ethanol indicated, even when RINs were taken into account. The low-ball prices suggest that interior refiners are struggling to get rid of March gasoline output, regardless of machinations in the world's bulk markets.
OPIS Real-Time Racks
***Monitor rack price changes as they happen, on the web and on your phone.***
--Reporting by Tom Kloza, tkloza@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
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Monday's historic slide in energy prices is resulting in historically high rack-to-retail gasoline margins in the United States, with today's level being the fourth-best margin on record.
The national average margin for regular unleaded is 57.4cts/gal, according to OPIS MarginPro data. That figure was only topped at the start of the financial crisis in 2008, when daily margins hit an all-time high of 59.3cts/gal on Oct. 6, hit 58.7cts/gal on Oct. 10 and came in at 57.6cts/gal on Oct. 7, the MarginPro data shows.
Tuesday saw a 16.4ct/gal spike in margins as crude oil prices sank by more than $10/bbl and prices for April RBOB fell 25.21cts/gal, pulling gasoline prices similarly lower in spot markets around the nation.
Margins are up 31.7cts/gal from a month ago and are 43.9cts/gal higher than where they were at this time in 2019, according to MarginPro.
A look across the country shows average margins topping 70cts/gal in 11 states, with the high coming in Oregon, with margins reaching a nosebleed level of 80.8cts/gal and in the Northeast the cluster of Vermont, Massachusetts Connecticut and New Hampshire seeing margins range from 76cts/gal to 71.2cts/gal.
An indication of the strength of margins is that only two states are seeing average levels below 40cts/gal, with Utah margins at the lowest in the nation at 17.4cts/gal and Idaho seeing an average of 26.3cts/gal. The South, where margins are normally low compared to the rest of the nation, is seeing margins average between 43.4cts/gal in Florida to $61.3cts/gal in West Virginia.
The spike in margins comes as retailers are already seeing record-breaking levels for the start of the year. Year-to-date margins are 27.5cts/gal as of Tuesday. That's 27% better than last year, which was the previous best for the Jan. 1 to March 10 period.
Even as energy prices appear like they will remain low through the year, retailers have reason for optimism. Margins, generally, perform better in the second half of the year, with first-half margins besting second-half levels only once going back to 2007. The high margins at the start of 2020 could usher in a period of strong profits for retailers.
OPIS RetailSuite
Manage every aspect of your retail fuel business with OPISRetailSuite’s web-based solutions that cover every aspect of your fuel business from real-time competitor pricing and alerts, to market data that includes margins, market share, and weekly volume trends.
--Reporting by Steve Cronin, scronin@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
Copyright, Oil Price Information Service
The U.S. Department of Energy (DOE) has called off a non-emergency sale of crude oil from the country's Strategic Petroleum Reserve (SPR), according to the DOE's Office of Fossil Energy which oversees all actions for the stockpile.
"Given current oil markets, this is not the optimal time for the sale, DOE spokesperson Jess Szymanski said in a statement, referencing "recent fluctuations in global oil markets." DOE will provide updated information "as market conditions change."
Petroleum futures trading on Monday took U.S. benchmark West Texas Intermediate on NYMEX down to $31.31/bbl, off by $10.15/bbl which was the largest one-day drop for the contract since Operation Desert Storm in 1991. Compared to where WTI began 2020 ($61.18/bbl), the crude's price has fallen by about 49%.
The sale of up to 12 million barrels from three sites in Texas and Louisiana was part of a three-year program to fund modernization of the SPR.
Announced on Feb. 28, the latest sale notice called for bids to be submitted by 2 p.m. ET today. Awards were to have been made no later than March 20 for deliveries to be made in April and May.
SPR crude was to have been sourced as follows: up to 6 million bbl from Bryan Mound, Texas; up to 3 million bbl from Big Hill, Texas; and up to 3 million bbl from West Hackberry, La.
The fourth location of the reserve is in Bayou Choctaw, La. As a whole, the U.S. SPR currently holds 634.967 million bbl of crude oil.
DOE was authorized to draw down and sell up to $2 billion worth of SPR crude oil for fiscal years (FY) 2017 through 2020 to fund modernization of the reserve. In addition, FY 2019 appropriations enacted on Oct. 1, 2018 allowed DOE to sell up to $300 million worth of SPR crude to carry out the SPR Life Extension Phase II project. Proceeds from that sale were deposited into DOE's Energy Security and Infrastructure Modernization Fund in FY 2019. A total of 4.2 million bbl was sold in the sale and delivered in April and May 2019.
Meanwhile, the U.S. has made a deal to give Australia access to the SPR in case of emergency.
As reported on March 9, Australia's Energy Minister Angus Taylor said he would be travelling to the United States this week to sign the agreement, which "will enhance Australia's resilience to international fuel disruptions by increasing our oil stockholdings."
The agreement solves both a political and supply problem for Australia, where the country's strategic reserves fall below levels required by the International Energy Agency (IEA). Australia, which imports 90% of its liquid fuels, has enough oil in storage to last 54 days, according to local reports.
That's far below the 90 days called for by the IEA.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Beth Heinsohn, bheinsohn@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
Copyright, Oil Price Information Service
Data compiled by Oil Price Information Service (OPIS) indicates that U.S. suppliers have reacted quickly to the change in global oil market prices and have made sizable reductions in wholesale rack prices. The changes average more than 11cts/gal countrywide and include diesel, gasoline, propane and biodiesel among the finished products impacted.
Every U.S. state has witnessed price changes that started this morning and have extended into the afternoon as suppliers reckon with a drop in crude prices over the weekend that amounted to some 30%, shoving West Texas crude into the low $30s and the mid-$30s for Brent.
Massachusetts and Nevada sported some of the biggest declines, which have averaged more than 16cts/gal combining all products. Some of the smaller increases amounted to half that in such states as Minnesota and Wisconsin.
Gasoline racks have declined more than any other product, with an average drop of 12cts/gal, followed by diesel at 10.41cts/gal, biodiesel at 9.82cgts/gal and propane at 4cts/gal.
It was largely the independent refiners and independent wholesalers who move over-the-rack barrels who punched prices lower.
Among the big refiners, Valero sliced prices an average of 16cts/gal through a large swath of its marketing sector. BP trimmed prices 10.36cts/gal across a smaller area, while Flint Hills cut prices an average of 12.4cts/gal across its markets, including the Southeast.
OPIS Real-Time Racks
***Monitor rack price changes as they happen, on the web and on your phone.***
--Reporting by Ben Brockwell, bbrockwell@opisnet.com;
--Editing by Barbara Chuck, bchuck@opisnet.com
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Oil analysts at major investment banks are scrambling to provide guidance for their clients today, and they are generally slicing 2020 price projections for Brent and/or WTI by double digits. Admittedly, most Wall Street analysts were prepared to react to the twin ills of coronavirus disease 2019 (COVID-19) and an inadequate OPEC+ outcome, but they did not anticipate a new calculus where there is a production/price war between Saudi Arabia and Russia.
Here's a very quick rundown of some of the considerations and conclusions reached by bank analysts in the last 24-48 hours:
--Bank of America Merrill Lynch: This bank was among the least bearish investment houses ahead of Friday's OPEC+ debacle, and they cling to some ambitious numbers.In a report called, "It Takes Two to Supercontango," bank analysts admitted that Brent oil prices might "temporarily dip into the $20s over the coming weeks," but they implemented modest cuts for target levels. BofA reduced average Brent prices for 2020 by just $9/bbl to $45/bbl and predicted a $41/bbl average for WTI, reflecting an $8/bbl downgrade.Analysts acknowledged that the Saudis no longer would pursue efforts to rebalance the oil markets and acknowledged that supply/demand projections suggest a major oil market surplus in 2020.The bank hints that the Saudis cannot survive cheap oil forever, and that suspicion might be behind the modest downgrade of 2021 Brent prices. Analysts now see Brent averaging $55/bbl next year, even though that reflects a huge increase from numbers on the forward curve. Analysts have downgraded the base case for demand in 2020 to see growth of just 250,000 b/d year on year, with a notable contraction in the first half of 2020. Longer term, the bank believes that "Brent is a $50-$70 bbl commodity" due to global oil production cost dynamics.
--BNP Paribas: The French bank had expected Saudi Arabia to revisit prices in light of the demand destruction from COVID-19, but the Saudi response via huge cuts to official selling prices (OSPs) was more than markets anticipatedComparisons were made to 2014, the last time OPEC could not reach a production agreement and prices fell sharply as a result."The drop in Saudi OSPs may be part of a 'game of chicken'," the bank said. "If neither side blinks and no compromise emerges, then we think oil prices might move lower in current economic context."BNP Paribas analysts point out that the emergence of a wide contango could limit the damage to spot prices as discounted barrels are put into storage to sell later at a higher price.
--Citi: "Brent crude oil looks like it will fall below $30 sooner rather than later, with no clear end in sight for a new price range," bank analysts told clients overnight. The low reached in the wee hours of the New York morning was $31.02 bbl.Citi declared that the crisis is "unprecedented," observing that even the 1973 Arab oil embargo did not hit supply AND demand. Saudi Arabia's decision to discount prices deeply and to increase output is aimed largely at Russia rather than the U.S., but collateral damage to shale will occur. Saudi Arabia could add 1 million b/d immediately but seems inclined to add about 400,000 b/d to March loadings. The Saudis may be motivated to bring Moscow back to the negotiating table to revisit a producer strategy.Global inventories will build significantly no matter what OPEC+ decides and should weigh heavily on prices into 2021. Citi sees demand dropping by 1.37 million b/d in 1H 2020 and projects an annualized inventory surge of 520 million bbl, a massive build under any circumstance. The bank believes that a massive adjustment is coming for global E&P companies and also warns that financial flows could exacerbate the pricing pain. A return of Libyan oil could push Brent well below $30/bbl, the bank adds.
--Credit Suisse: The bank observed this morning that Saudi Arabia has declared an all-out price war. Like some other analytical houses, the bank notes that the Saudis could quickly increase output to 10 million b/d with the possibility of eventually hitting 12 million b/d.The scale of this oversupply -- coupled with the delay between rig reduction and actual production impacts -- could force oil prices toward cash costs of high-end producers (the low $20s) and rebalance markets over the near term.Credit Suisse had been looking for 530,000-610,000 b/d of U.S. shale growth in 4Q20 and 2021, but now sees perhaps 200,000 b/d to 300,000 b/d of year-on-year growth. The bank observes that the downturn will be much uglier than the 2014-2016 decline among U.S. producers.
Capital is tighter and the big efficiency gains are in the rear-view mirror.
--Goldman Sachs: The investment house has multiple possible scenarios. However, top commodities strategist Damien Courvalin told clients that this was the equivalent of the 1Q 2009 demand shock coming with a 2016-like OPEC production surge. Goldman Sachs cut 2Q and 3Q Brent forecasts to $30/bbl and suggested that possible dips could go near wellhead cash costs close to $20/bbl. The events of last Friday bring back the "New Oil Order" where low-cost producers increase supply from spare capacity and force higher cost producers to reduce output.
--HSBC: The international bank drastically reduced its forecasts for Brent and WTI, dropping the benchmark targets to $49/bbl and $44.80/bbl, respectively.
Again, that is sharply higher than what Monday morning markets are reflecting.The greatest price damage is forecast for the second quarter with Brent projected at $42/bbl and WTI at $38/bbl. Those numbers are $18/bbl lower than the bank's previous outlook.Zero demand growth is now forecast for 2020, with a contraction of 1.3% in the first half of 2020 thanks to the coronavirus.
A recovery in demand is still expected in 2H 2020. HSBC expects U.S. production growth to narrow to about 300,000 b/d in 2020 and ultimately decline by 500,000 b/d in 2021.
--Morgan Stanley: Analysts there believe oil is sharply oversupplied and predicted that Brent needs to fall to $35/bbl in the second quarter and $40-$45/bbl in the second half of 2020. Given that markets have already visited levels below these numbers, a revised report may be forthcoming shortly.Morgan lowered expectations for Brent to $35/bbl in 2Q20 but sees quarterly rises to $40/bbl; $45/bbl; and $50/bbl for the next three quarters. The revised targets still reflect drops of $10/bbl (4Q) to $22.50/bbl (2Q) and new sequential targets for WTI are now $30/bbl to $45/bbl over the rest of 2020.The investment house also hearkens back to the 2014 OPEC meeting for perspective. OPEC output rose 1.5 million b/d over the subsequent 12 months. WTI needs to fall below the average wellhead break-even level (about $40/bbl), and that would ostensibly spark a drop of 200,000 b/d in U.S. output between the exit of 2019 and December 2020. Before the weekend, the bank had been anticipating 400,000 b/d of growth.Morgan Stanley believes that the global oil market will deal with an oversupply of about 800,000 b/d in 2020.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Tom Kloza, tkloza@opisnet.com, Denton Cinquegrana, dcinquegrana@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
Copyright, Oil Price Information Service
Spot prices for propane and butane in the Mont Belvieu and Conway trading hubs heading into the afternoon have rebounded off historic lows recorded this morning, but concerns remain high for longer-term prospects amid the upheaval in global markets.
Despite the recovery, Mont Belvieu non-TET (Enterprise) normal butane was on track to end the day with its lowest average price in more than 18 years, according to OPIS TimeSeries data. By 12:30 p.m. CDT, the price had posted an intraday high of 39.875cts/gal from an early low of 34.5cts/gal, for an implied midpoint of 37.1875cts/gal.
The last time similar levels were seen was in Jan. 2002, with a midpoint of 32.875cts/gal recorded on Jan. 14 during a month when the daily average price ranged consistently in the low- to mid-30cts/gal.
The propane market had also flirted with multi-decade lows early on, but the midday rebound pared that record back to just a handful of years.
Mont Belvieu non-TET propane anys recovered to 33.375cts/gal from a morning low of 29cts/gal for an implied full-day mean of 31.1875cts/gal, while TET (Energy Transfer) propane moved up to 32cts/gal from 27.75cts/gal at the start of the session for an average of 29.875cts/gal. Conway propane was up to 30.5cts/gal after recording a 26cts/gal low for an average of 28.25cts/gal.
All three average prices were last seen at similar levels back in Jan. 2016, according to OPIS TimeSeries data.
Despite the rebound, the day's average price for TET propane as of 12:30 p.m. CDT remained 17.3% adrift of Friday's close. Non-TET propane was down 15.42% while normal butane was tracking 20.35% lower.
Downstream at U.S. racks, wholesale propane prices took a hit, falling 1.75-3.00cts/gal at a number of propane terminals, while a few of the Midwest racks saw price drops of 5.00-5.25cts/gal.
"Obviously, if the price of crude continues to descend, we know propane is going to trend lower," said a market watcher, though he added that the selloff appeared to be overdone.
The winter propane season is winding down in the Midwest, where the season has been fairly mild. "I'm going to guess a lot of people will get their last fill up in a week or two," said the source of residential propane heating customers.
Mild winter aside, Midwest marketers have enjoyed steady propane margins ranging from 30-50cts/gal in most areas. Parts of Colorado have seen margins ramp up as high as 80-90cts/gal.
Today's price moves in stateside LPG came in reaction to a one-two punch inflicted upon crude oil markets on Friday and Saturday. Russia set the ball rolling by discontinuing a three-plus year production cut agreement with OPEC.
Saudi Arabia responded a day later by announcing that it would ramp up its own crude oil production, suggesting that output going forward would top 10 million b/d and reach as high as 12 million b/d, and simultaneously slashed the official sales price by $6-$8/bbl.
The resulting collapse in crude oil has exacerbated challenges facing an already over-supplied LPG market.
The end of winter is expected to trigger the traditional decline in LPG prices regardless of external factors. But this year, the situation was top-heavy even before the weekend. The situation is particularly grim in PADD3 (Gulf Coast), the main exporting region.
Propane-propylene inventories in PADD3 as of Feb. 28 stood at 50.9 million bbl according to the Energy Information Administration (EIA), 45.4% higher than the 35 million bbl seen in storage for the corresponding week in 2019.
New fractionation capacity to the tune of 1.4 million b/d would be added in PADD3 by the middle of 2021, and this is projected to push a corresponding increase of LPG into the supply pool.
With domestic demand for LPG expected to remain flat, exports are the main avenue for America to reduce its supply overhang. However, waterfront infrastructure constraints mean that all of the burgeoning surplus cannot be siphoned off.
Weekend events add a new dimension to these well-reported challenges.
Observations from NGL market watchers this morning highlighted the following major themes:
--Increased Saudi Arabian crude oil production implies increased LPG production. These barrels are expected to vie for market share with burgeoning U.S. supplies. Yanyu He, IHS Markit executive director for NGLs, said that as a rule of thumb, 1.8 million mt of LPG production a year is associated with 1 million b/d in crude oil production. Hence, if Saudi Arabian production were to ramp up to its capacity of 12 million b/d from its recent pre-weekend level of around 9.7 million b/d, this could imply an annualized increase of some 4 million mt in the total global LPG supply.
--This comes when global demand could be compromised for a prolonged period on concerns about coronavirus disease 2019 (COVID-19). As one commentator put it:
"The normal wisdom that 'the cure for low prices is low prices' may not hold true this time. Low U.S. prices would not automatically imply more overseas demand, because this is a global price phenomenon." Narrowing propane export margins from the Gulf Coast to Asia through last month despite falling freight corroborate this fact.
--Petrochemical companies in Japan and South Korea have scaled back their naphtha crackers amid COVID-19 concerns. This has caused a potential market for U.S. propane to dry up.
--Lower crude oil prices could lead to lower crude oil production stateside only gradually. During the 2014-2015 price fall, the full reduction in shale production filtered through only after about a year, one expert recalled. By this yardstick, the brakes might not be applied on crude oil production immediately; so low NGL prices might not immediately inhibit the associated supply of NGLs either.
Reported Chinese interest in importing U.S. LPG again could be a potential bright spot. But it may take several months for these flows to materially develop, and this would remain subject to how COVID-19 plays out.
"The picture for LPG prices stateside was bearish before last weekend, and it is even more bearish now," one expert remarked.
This may imply a prolonged U-shaped recovery in LPG prices instead of a quick V-shaped one, he suggested.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by Rajesh Joshi, rjoshi@opisnet.com, Jessica Marron, jmarron@opisnet.com, Mary Welge, mwelge@opisnet.com;
--Editing by Michael Kelly, michael.kelly3@ihsmarkit.com
Copyright, Oil Price Information Service
March 9, 2020
Oil product prices in Asia plummeted on Monday following a breakdown in talks between OPEC and key ally Russia on output cuts, but price falls have so far lagged the sharp losses seen in the crude markets.
May ICE Brent futures were at $33.90/bbl as of 9:55 am Singapore time, over 36% lower than Singapore's close of $49.08/bl last Friday. The last time crude futures fell by over 30% between trading sessions was at the start of the first Gulf War in January 1991, according to data from the Energy Information Administration.
Crude futures had tumbled after the collapse of OPEC's alliance with Russia, which was swiftly followed by Saudi Arabia slashing offers for its crude oil over the weekend, sparking talk of price wars among the major oil producers.
Asia oil product prices similarly tanked on Monday but at a rate slightly lower than crude, which meant that refining margins actually rose for most products.
April Singapore 92 RON gasoline swaps tumbled 26% to $39.39/bbl Monday morning in Asia from Friday's close, while its crack spread gained 1.5% to $4.81/bbl.
April Japan naphtha swaps fell by the same percentage to $300/mt but its crack spread rose by over $6/mt to $44.175/mt, according to broker data.
April Singapore jet fuel prices and 10 ppm sulfur gasoil slumped 24% and 23% to $42.32/bbl and $44.55/bbl, respectively but the crack spread rose by $3.25/bl and $3.21/bl to $10.00/bbl and $12.23/bbl respectively.
May Singapore 0.5% sulfur fuel oil swaps fell by a similar magnitude of 23% to $293.50/mt during morning trading while its crack spread rose by almost $2/bbl to $8.77/bbl.
The rise in crack spreads however might be only short-term relief for refiners already struggling with narrow margins.
"Refining margins may rise slightly for a day or two as falls in product prices could be slower than crude, but it may not last longer unless demand revives," a South Korea-based analyst said.
Refiners throughout Asia have already been cutting runs even before the latest collapse in crude prices, as the rapidly spreading coronavirus disease 2019
(COVID-19) severely curtailed oil demand.
"This is a clear double whammy," the analyst added.
The sharp fall in prices are expected to affect trading and price negotiations.
Market participants now expect spot jet fuel and gasoil cargoes awarded previously to be cancelled as prices for products fell to a new low.
"Cancelling a spot tender, and paying penalty, then buying at current levels is probably more profitable now," a trader said.
The impact of increased production from the Middle East could also throw yet another spanner into an Asian LPG market already buffeted in recent months by the US-China trade war.
China had allowed for hefty import tariffs to be removed from US-origin LPG imports only on Mar 3, which meant that both US and Middle East-origin LPG are now subject to the same 1% import tariff.
But the prospect of increased production in the Middle East meant that LPG cargoes from that region might remain competitively priced relative to US cargoes, market sources said. The Saudi April CP, which sets the contract price for term LPG cargoes from Saudi Arabia, is likely to be at a discount to Cost and Freight (CFR) Japan prices as a result, market source said. Paper markets had indicated on Friday that April CP would be at a $8/mt premium to CFR Japan prices.
Further downstream, aromatic prices too fell sharply. Benzene spot prices plunged by an estimated $102.50/mt or 16.5% after offers for benzene parcels loading April and May were slashed by as much as $100/mt to $525 and $520/mt FOB Korea, respectively by noon in Asia.
OPIS Mobile News Alerts provides instant access to real-time petroleum industry news from veteran OPIS reporters. For over 35 years, OPIS has guided jobbers, retailers, suppliers, refiners, traders, brokers, end users, and other industry professionals through a sea of volatility.
--Reporting by OPIS Asia team;
--Editing by Rob Sheridan, rob.sheridan@ihsmarkit.com
Copyright, Oil Price Information Service
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