Interactive: Platts Periodic Table of Oil – 4th edition adds carbon intensity data

Saudi Aramco is expected to lower its official selling prices for June-loading crudes following tepid Asian demand fundamentals, with the OSP differentials retreating from the record highs seen this month, market sources told S&P Global Commodity Insights. Earlier in April, Saudi Aramco raised its official selling prices for Asia-bound crude loading in May by a range of between $2.70/b and $4.40/b to the highest ever recorded, S&P Global data showed. The June OSPs will likely be slashed by $4-$6/b from May levels, trade sources said in the week ending April 29. "June OSP should be down from previous month, reflecting weaker trading fundamentals. Maybe by at least $4-$5/b down from previous month, the Dubai structure is lower too," said a Japan-based crude oil trader. The Dubai cash/futures spread -- understood to be a key element in OSP calculations -- averaged $3.65/b over April, down from an average of $9.25/b in March, S&P Global data showed. "June OSP adjustment will be as per market structure, maybe reduce by at least $5-$6/b," said a regional crude oil trader. Asian demand is likely to drop in the new July trading cycle as China battles another wave of the coronavirus resurgence, while Japanese demand could remain lukewarm amid some turnarounds, traders said. "Based on the current situation, I assume producers must reduce [June-loading] OSPs," said a China-based crude oil trader. With the expected drop in OSPs, traders anticipate Asian refiners to maximize their term volume nominations. "Term buyers will continue to take maximum term allocation, they won't want to take cargoes at the mercy of spot market which changes too quickly," the second Singapore-based crude oil trader added. Demand fundamentals Demand sentiment for July-loading barrels of Middle East crudes remained mixed among Asian buyers, although Indian demand could offer some buy-side support. China continues to battle fresh coronavirus outbreak through lockdowns and additional testing, while Japanese refinery turnaround season could keep fresh demand subdued, traders said. Far East Russian crudes meanwhile, have also failed to grab sufficient interest from Asian refiners. Earlier this week, Russia's Rosneft Oil Company failed to attract buyers in its sell tender for May-loading barrels of Far East Russia's ESPO Blend and Sokol crudes. Asian buyers avoided trading Russian oil amid concerns over reputation, payment and logistics, leaving Russian energy supplies reeling despite competitive prices. India could pivot away from Russian crude to Middle East energy supplies instead, after US President Joe Biden urged Indian Prime Minister Narendra Modi to diversify the country's oil imports away from Russia during a virtual meeting earlier in April. "Indian crude demand may also turn away from Russian crude and shift towards Middle East grades, that may also offset the impact from weaker Chinese demand," said the Japan-based crude oil trader. Although Chinese refiners could still be taking Russian crude, volumes may be limited as their refinery runs have been lower, according to a Singapore-based crude oil trader.

The crude market isn’t that tight, but the oil market is. The bullish narrative going into the Russian-Ukraine crisis was driven by a short-term perspective and flawed thinking around crude fundamentals. Now the excessive strain on supplying transport fuels is turning bullish fiction into fact. Market watchers may be guilty of viewing leading indicators out of context. Take the apparent lack of oil in commercial storage. OECD stock levels are indeed below the five-year average and have sunk to multiyear lows. But what this fails to recognize is that by any longer yardstick these inventories are still high and were over-inflated by the shale boom the previous decade, where an excess of light sweet crude had nowhere to go except into tanks. The International Energy Agency reported OECD total industry stocks fell by 42.2 million barrels to 2,611 million barrels in February, which still puts inventories above the 2013 nadir and even above averages seen a decade earlier. The storage argument often overlooks China, too. The second biggest oil consumer has built up its capacity over the past five years, and crude stocks increased 20% since 2019, according to various analyst estimates. Market watchers also point to OPEC+’s lack of global spare capacity, which, while true, downplays the fact that for much of the last two decades the average oil buffers have not been that much higher than the 2 million b/d mark. There is still another 1 million b/d extra that could be brought on by the end of the year if Iran gets the green light even if that is still in the balance. Maybe that’s why OPEC+’s recent meeting noted “the consensus on the outlook pointed to a well-balanced market, and that current volatility is not caused by fundamentals, but by ongoing geopolitical developments.” The argument from some corners that the mandated IEA strategic reserves release leaves the system short of emergency back-up and that the crude would have to be bought back at some point is also bizarre. It still means at least 120 million barrels entering a market in the next six months, and thus an increase in supply, that has seen few barrels lost so far, and around a quarter of that being oil products and the rest being crude. IEA oil stock draw contributions (million barrels) US 60.559 Japan 15.000 South Korea 7.230 Germany 6.480 France 6.047 Italy 5.000 UK 4.408 Spain 4.000 Turkey 3.060 Poland 2.298 Australia 1.608 Netherlands 1.600 Greece 0.624 Hungary 0.531 New Zealand 0.483 Ireland 0.451 Finland 0.369 Lithuania 0.180 Estonia 0.074 Total 120.000 Source: IEA “Despite a major war and the possible loss of some Russian crude, oil prices remained below $120/b, which proves the point that market fundamentals do not support $100/b oil,” said independent energy analyst Anas Al-Hajji. Then there were the geopolitical jitters that saw crude prices spike from the cusp of triple digits toward $140/b in March on fears of sanctions, self-sanctions, boycotts and Russian oil being removed from the market. Even now commentators are keen to point to the lost barrels when there is patchy evidence the oil numbers are falling in any significant way. S&P Global Commodity Insights analysis notes that “Russian oil exports so far continue to largely flow,” with product loadings from Russian ports proving resilient in March, even for diesel seen as the tightest part of the product mix. The destinations may have changed, but the volumes haven’t. A look at the differentials for key European grades assessed by S&P Global also indicates a market awash with light sweet crude. Even the IEA noted in its monthly oil market report April 13 weaker-than-expected demand along with steady output rises from OPEC+ and the US should offset lost Russian supplies to help “bring the market back to balance.” Crunch time But it’s crunch time in the market as current arrangements for Russian purchases made before the war come up for renewal. S&P Global expects to see a loss of nearly 3 million b/d in Russian crude and products exports in the coming months as more buyers shun Russian oil. And it’s the middle of the oil barrel that will bend the market out of shape. The lack of diesel stocks and the importance of Russian diesel supply to Europe is showing up in the high gasoil and diesel cracks. Stocks of diesel and gasoil in the Amsterdam-Rotterdam-Antwerp hub in Northwest Europe dipped 1.6% on the week to an 11-year low of 1.439 million mt in the week to April 20, Insights Global data showed April 21. And TotalEnergies’ European refining margin indicator surged to $46.3/mt in the first quarter, up from $5.3/mt a year earlier, as distillate cracks ballooned on the back of the Russia crisis, it said April 19. Goldman Sachs said in a research note “the current distillate shortage is even stronger than in 2008,” pointing to the low stocks and large seasonally adjusted deficit which is getting worse, along with “a large increase in jet fuel consumption this summer due to the return of international travel” and continued gas-to-oil switching. Indeed, refiners will often wiggle between maximizing production of jet or diesel, and with both likely being tight, options to plug the gap become limited. Add to that the fact that US summer driving season will start to put pressure on gasoline supply, and the oil products mix may start looking extremely tight. Standard Chartered noted that “oil price volatility has been mirrored by volatility in estimates of key fundamental indicators,” pointing out that while the downside to Russian oil output is large, so is the downside risk to demand. It then comes down to how much that eases the pressure on demand for transport fuels along with the oil products released from the IEA. The fundamentals could soon start to catch up to the bullish sentiment. That leaves the question as to whether the market is pricing in the risk or has misunderstood it, potentially ending up being right for the wrong reasons.

Concerns over energy security as a result of the ongoing Russia-Ukraine war may spur capacity expansion and diversification of oil and natural gas supplies in the next few years, which could prompt more longer-lead projects which industry has shied away from in recent years, the top executive of oil services giant Schlumberger said April 22. A half dozen years of oil prices that hovered around $45/b-$50/b beginning in 2015 eventually led upstream producers to focus on so-called short-cycle projects that provided a relatively quick payback starting roughly six to 24 months after being greenlighted. But longer-cycle, pricey projects that take years or even a decade to produce first oil could also make a comeback as the thirst for supply diversity and security become major priorities for upstream producers, Schlumberger CEO Olivier Le Peuch said during his company's first-quarter 2022 earnings conference call. "This new dimension will have long-lasting positive implications for energy investments over the next few years," Le Peuch said. Energy security that drives further capacity expansion and demand for more diverse oil and gas supply will also support additional long-cycle development projects, exploration activity, and brown feed regulation programs, he said. Long-cycle projects include offshore and large-capacity onshore expansions that national oil majors continue to develop. In the Middle East, a few countries have already committed to capacity expansions this year and beyond. And "offshore you have seen some [final investment decision] approvals," Le Peuch said. "You have seen some exploration drilling resuming even last quarter that would turn into FID and into a subsea and deepwater activity uptick in the second half and further in 2023." 'Evolution' in the energy landscape The past few months have seen an "evolution" in the energy landscape after Russia threatened, then attacked, Ukraine earlier this year, Le Peuch said. For one thing, crude prices that shot up this year to more than $100/b from the mid-$70s/b mostly owing to those countries' ongoing war, have created "favorable conditions" for oilfield services and equipment pricing improvement, even as demand for them expanded globally, he said. "This [pricing improvement] will be a defining characteristic of this upcycle," Le Peuch said. Moreover, higher service/equipment pricing is "absolutely critical" to support oilfield service/equipment providers' financial returns and investments in capacity needed to deliver on both the short- and long-term oil and gas supply the world needs." Ongoing short-cycle investments in the US are being led by private producers which domestically account for over 60% of the country's land rig count, and that volume is growing amid a "gradual" increase by public operators, said Le Peuch. At the same time, supply chain and capacity bottlenecks hinder growth somewhat, as does exploration-and-production capital discipline, which began to take hold in E&P operators' corporate strategies even before the coronavirus pandemic set in during early 2020. Le Peuch's comments echo and expand on remarks made earlier in the week by his counterpart at peer oilfield services/equipment giant Halliburton. Similar to Le Peuch, Halliburton CEO Jeff Miller said supply dynamics have "fundamentally changed" because of investor return requirements, public ESG commitments, and regulatory pressures that make a commitment to longer-cycle projects difficult for operators. Drawbacks of long-cycle projects The nature of long-term projects prevents a quick response to market price signals and results in oversupply, whereas short-cycle projects create "a perpetual threat of undersupply" that supports commodity prices, he said April 19. Miller foresees an industry over the next several years characterized by short-cycle upstream projects, development rather than exploration, and tiebacks to existing production hubs over costly, time-consuming new infrastructure builds—all of which give operators more flexibility to make timely and appropriate investment decisions. Once long-cycle projects begin, investment must continue and production cannot quickly respond to market price signals, resulting in market oversupply. The pivot to short-cycle barrels creates the opposite effect, a perpetual threat of undersupply that supports commodity price, he said. But given that backdrop, some intriguing questions emerge, according to Evercore ISI analyst James West. "We think there will be some interesting choices ahead as inflation and higher activity levels drive further price increases," West said in an April 21 investor note. "Do operators continue to pay higher prices to get their preferred equipment and well construction/completion designs or do they alter those designs potentially sacrificing efficiencies for lower pricing?" "Some examples would be using a Tier II diesel frac spread, an older, smaller AC rig, and welded instead of seamless pipe," he said. Schlumberger earned $5.9 billion in revenue during Q1 2022, down 4% sequentially but up 14% year on year. The sequential drop came largely from international operations – including impacts on Russian operations and seasonal weather events – which earned $4.63 billion, down 5%, while North American revenues were flat at $1.28 billion.In Q1, Schlumberger suspended new investment and technology deployment to its Russian operations, Le Peuch said. Schlumberger's Q1 net income was $510 million or 36 cents/share, down 14% sequentially but up 70% year on year. "Internationally, short-cycle investments are set to accelerate with the seasonal rebound in the second quarter and more strongly in the second half of the year, led by the Middle East and the key international offshore basins," Le Peuch said.

Oman, the biggest Middle East oil producer outside OPEC, increased its total monthly crude production by 12.2% in March from February, official data showed, amid a higher OPEC+ quota. Oman, which is a member of the broader OPEC+ coalition, in March pumped an average daily production of 829,255 b/d, slightly above its 829,000 b/d quota, which rose from 821,000 b/d in February. Total monthly oil exports to China, the top importer of Omani crude in February, fell in March by 17%, while oil exports to India, the No. 2 importer of Omani crude in February, more than doubled. Total monthly oil and condensate exports rose 11% in March from February. OPEC+ ministers are due to meet May 5 to decide on June production levels. Falling output Oil production by OPEC and its allies fell in March from February for the first time in more than a year, the latest S&P Global survey found, contributing to a tightening market thrown in flux by the Russia-Ukraine war. Western sanctions began biting into primary non-OPEC partner Russia's oil flows, and sizable disruptions in Kazakhstan and Libya also led the coalition's production lower, the survey found. OPEC's 13 members raised output by 60,000 b/d to 28.73 million b/d, but that was more than offset by a 160,000 b/d decline by the bloc's nine allies, who pumped 13.91 million b/d.

In the ever-evolving crude market, the dearth of crude from Iran, Venezuela and, most recently, Russia, has led Asian refiners to buy up tight supplies of heavy Latin grades as a replacement. Buying interest for these grades from Mexico, Colombia and Ecuador has been reported in recent months, but availability is limited and a surge in supply from the US could send the market spinning yet again. Americas crude manager Laura Huchzermeyer leads the discussion with Maria Eugenia Garcia, senior editor for Latin American crude, Pankaj Rao, editor for Asian and Middle East crude markets, and Dania el Saadi, senior editor of Middle East News. This Oil Markets podcast was produced by Jennifer Pedrick in Houston. More listening options: No content (including ratings, credit-related analyses and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified, reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor's Financial Services LLC or its affiliates (collectively, S&P).

At a recent oil conference in Argentina, one of the most-bandied about words was “potential.” That and Vaca Muerta. The possibilities for oil and natural gas production growth in the shale play, executives said, is “fantastic,” “gigantic,” “immense,” “magnificent” and so forth. There are reasons to be rosy. Vaca Muerta is one of the world’s biggest shale deposits, and the extraction costs have dropped close to the levels in comparative formations in the United States. This spurred forecasts at the conference that Vaca Muerta could help nearly double Argentina’s oil production to 1 million b/d by 2026, allowing exports to surpass 500,000 b/d by then, up from less than 100,000 b/d now. Gas production, now at 130 million cu m/d, could surge even more to make Argentina a rival to Australia and Qatar in the LNG market at a time when demand is growing for gas in the energy transition to net-zero carbon emissions by 2050. The trouble is that all this talk of potential has been heard before. Vaca Muerta’s geology may be great, but the conditions for doing business in Argentina are far from that, executives said at the conference. To be sure, the chance of losing money in Argentina, when measured by its country risk premium, is now at about 1,700 points, according to J.P. Morgan Chase’s EMBI+ emerging market bond index that takes into account such factors as the economy, politics and public finances. That is six times greater than the risk in neighboring Brazil, which produces five times more oil and has ample offshore potential for growth. Even so, a few advances have been made over the past year or so in Argentina to fuel this new optimism that the country, long dogged by economic crises, is once again – or finally – on the right track to speed up the development of Vaca Muerta. A big advance came last month when the International Monetary Fund approved a new loan program for Argentina, gaining the country more time to pay the $44 billion it owes. The agreement includes a series of fiscal and monetary targets that should help stabilize the economy and widen access to international financing. It’s needed. The economy, which fell into its latest upheaval in 2018, is struggling with more than 50% inflation, 37% poverty and dangerously low international reserves. The government has responded with capital, price and trade controls, but these have made it hard to run businesses, curbed profit potential and prompted some companies to pull out. Latin America-focused GeoPark left this year, while China’s Sinopec and US-based ConocoPhillips did so last year, and US-based Schlumberger sold out of its Vaca Muerta acreage the previous year. While the likes of Mexico’s Vista Oil & Gas, Equinor and Shell have taken advantage to increase their stakes; they say their bets are for long-term growth. In the meantime, the poor conditions are keeping a lid on overall investment, led by two widely cited deterrents. One is that the government is keeping crude prices artificially low at about $60/b domestically, nearly half of the around $110/b for Brent, the international reference price followed in Argentina. The second is the capital controls designed to limit the flight of dollars from the economy. In effect, companies can bring money in but they can’t take it all out, not even to pay dividends, import equipment or service their debts. The result is that oil companies are limited, for the most part, to investing out of cash flow as few international banks or investors want to risk the billions of dollars need to speed things up. “It’s like we’re going one mile per hour” when compared with US shale development and Vaca Muerta’s potential, said Horacio Marin, managing director of exploration and production at Tecpetrol, Argentina’s third-biggest gas producer. Looming bottlenecks There’s an urgency to step up investment. Vaca Muerta, which came into development in 2012-13, now accounts for 39% of the country’s 571,000 b/d of oil output and 52% (along with tight plays) of the 130 million cu m/d of gas, according to Energy Secretariat data. “If we don’t do anything with infrastructure, production will hit a ceiling in the next couple of years,” said Rodolfo Freyre, vice president for gas, power and business development at BP-backed Pan American Energy, the country’s second-biggest oil producer and fourth for gas. Horacio Turri, executive director of exploration and production at Pampa Energia, the country’s fifth-biggest gas producer, said Argentina faced a similar dilemma at the end of the 19th century in agriculture. Its vast farmlands could produce heaps of food to meet global demand, but to make that happen a huge railway network had to be built. And that is exactly what happened, helping make Argentina a breadbasket for the world and, for a few decades, one of the planet’s strongest economies. “The railways of the 19th century are the gas pipelines of the 21st century that we need to be able to monetize this resource by going out into the world to compete in sales,” Turri said. If the energy transition lasts 50 years, “we would need to multiply by 10 the production in Vaca Muerta,” he added. A few advances This is where progress is being made. Oldelval, an oil pipeline operator in Vaca Muerta, plans to invest $500 million over the next few years to double its transport capacity to about 500,000 b/d. At the same time, a 100,000 b/d pipeline to Chile from Vaca Muerta is being revamped to start operations as soon as this year. The prospects for the gas business have also started to improve. A little over a year ago, the government created an incentives program that has boosted wellhead prices to more profitable levels of around $3.50/MMBtu, leading to a rise in production to 130 million cu m/d from a recent low of 114 million cu m/d in April last year. While production is still shy of the 140 million cu m/d of average demand that peaks at 180 million cu m/d in winter, Vaca Muerta can fill this gap with a lot of extra supplies for exporting, executives said. To make this happen, the government this year launched a three-year project to build a pipeline that can carry up to 44 million cu m/d to expand domestic sales and exports, beginning with Brazil and Chile. The first stage of the line, with 11 million cu m/d of capacity, is due to come into operations by mid-2023. Marcos Bulgheroni, the CEO of Pan American Energy, said exports to Brazil alone could increase to 40 million cu m/d from minor amounts today. But the biggest growth, he said, will come with LNG. At the conference, he proposed setting up a consortium to build a liquefaction terminal with 13 million tons per year of capacity, an investment of up to $15 billion, that would help Argentina increase exports at a time when buyers are looking for new sources other than Russia. Transportadora de Gas del Sur, a gas pipeline operator, may be the first to get such a project underway. CEO Oscar Sardi said he expects to have the plans in place by the end of the year for the project, a partnership with US-based Excelerate Energy. The liquefaction plant, he said, would be built in modules, each with a capacity of 4 million cu m/d, allowing Vaca Muerta producers to start selling LNG as estimates suggest that global demand will nearly double by 2030 from this year. “We either start this or we’ll miss the chance,” Sardi said.

In this week's highlights: Oil markets to focus on monthly reports from OPEC and the International Energy Agency, uncertainties around Russian gas continue to preoccupy European markets, and the coal embargo piles feedstock pain on the power sector. OPEC and IEA monthly reports this week (00:10) Russia gas worries continue for Europe (01:00) Coal embargo piles feedstock pain on power market (02:09)

In this week’s Market Movers Americas, presented by Colleen Ferguson: • Replacing Russian oil skyrockets tanker freight (00:20) • Rail issues hinder US spot coal movements (01:11) • Heat wave set to widen spot gas basis spreads (01:49) • MISO to unveil capacity auction results (02:33) View Full Transcript In this week’s Market Movers: Europe’s efforts to replace Russian oil make tanker freight surge, slow rail cycle times impair coal movements, warm weather in the Northeast US is set to widen spot gas basis spreads, and MYSO will publicly discuss its latest capacity auction results. Starting in shipping, Europe’s efforts to replace 2.7 million barrels per day of self-sanctioned Russian crude and nearly 900,000 barrels per day of clean oil products will continue to drive US Gulf Coast-loading tanker freight rates this week. Since Russia’s invasion of Ukraine, freight rates on the USGC-Europe routes have risen 74.1% for crude tankers and 260% to transport 38,000 metric tons of mainly diesel and naphtha cargoes. High export volumes have rapidly depleted the number of tankers available to load on the US Gulf Coast, and charterers will increasingly eye upsizing stems wherever possible. The Very Large Crude Carriers and Long Range 1 tankers will see heightened interest for voyages to Europe. In coal, slow rail cycle times are preventing US spot thermal and metallurgical coal from getting to seaborne markets despite surging global demand amid the war in Ukraine. Ports have coal export capacity, but there’s no rail service available to bring the additional coal to market. Without enough trains to take coal away, production has stopped at some mines as stockpiles reach permitted maximums. This brings us to our social media question of the week: With transportation issues ongoing, are end-users in danger of energy shortages or will suppliers provide it at any cost? Tweet us your thoughts. Moving to natural gas, a minor heat wave forecast in the US Northeast for April 12-14 is expected to slash heating demand in the area for natural gas. This could dramatically widen regional spot gas prices’ discounts to cash Henry Hub in the near term. S&P Global projects that Northeast residential-commercial demand will average 5.3 billion cubic feet per day for that period, down 45% from the April 1-7 average of 9.6 billion cubic feet per day. CustomWeather forecast that average temperatures in the Northeast will rise into the low 60s Fahrenheit for April 12-14, which would be about 10 degrees above normal for mid-April. And finally in power, the Midcontinent Independent System Operator will discuss its latest capacity auction results during a public meeting on April 15. MYSO will outline the price and amount of capacity that market participants obtained to meet resource adequacy requirements for the period starting June 1. The planning resource auction ran from March 28 to March 31. The Platts Atlas of Energy Transition is your map to the sustainable commodity markets of the future. You can explore the Atlas by visiting the address displayed on your screen. Thanks for kicking off your Monday with us and have a great week ahead.

Japan plans to tap 9 million barrels of oil from national petroleum reserves as part of its contribution to the International Energy Agency's joint effort, a source at the Ministry of Economy, Trade and Industry said April 8, which would mark the country's first release from national reserves. The country also plans to release 6 million barrels from privately-held oil reserves, giving it a total of 15 million barrels release for the IEA's largest ever stock release of 120 million barrels. Japan's oil release from the country's national oil reserves will be the first under the country's petroleum stockpiling law since the reserves were established in 1978, the source said. The latest IEA move comes after the US pledged in the week ended April 2 to tap 180 million barrels of oil, effectively releasing 1 million b/d for six months from May, in a bid to alleviate market concerns over potential shortages from a drop in Russian oil exports. The IEA also clarified April 7 that over the next six months, around 240 million barrels of emergency oil stocks -- the equivalent of well over 1 million b/d -- will be made available to the global market. That implies the total release would include the 62.7 million barrels announced by the IEA on March 9, 30 million barrels of which is coming from the US. Japan also extended April 8 its previous release of 7.5 million barrels of crude and oil products from privately held petroleum reserves by six months, the source said. The release of 7.5 million barrels of oil as part of the last IEA release, which had been expected to be completed during a 30-day period to April 8, was extended to Oct. 8 from April 9 in response to a recent request from the IEA amid the prolonged Ukraine war, the source said. Japan's release of 7.5 million barrels of crude and oil products equates to four days of mandatory stockpile volumes. To do so, the country has allowed local refiners and oil products importers to lower their stockpiles. Tender sales Japan also sold April 8 an additional 300,000 kiloliters, or 1.89 million barrels, of Hout crude from its national petroleum reserves via a public tender, the source added. This was the last sale in its joint efforts with the US and other countries to stabilize oil prices. In the latest tender, Japan offered up to three shipments of Hout crude from the Shirashima national oil reserves terminal in Kita Kyushu City in the southwest for delivery May 20-Aug. 31. Following the sale of the Hout crude -- produced in the Saudi Arabia-Kuwait Neutral Zone -- Japan's crude sales from national oil reserves have amounted to a total of around 660,000 kiloliters, or 4.15 million barrels. Japan sold March 9 260,000 kiloliters, or 1.64 million barrels, of Khafji and Hout crudes produced in the Neutral Zone from its national petroleum reserves via public tenders, after selling about 100,000 kiloliters, or 629,000 barrels, of Oman crude from the reserves via a Feb. 9 public tender. Japan's serialized sales of national petroleum reserves was made by advancing its planned sales of crude for replacement in the national reserves without violating the country's petroleum stockpiling law. In recent years, the country has been replacing medium and heavy crude stocks in the national petroleum reserves with lighter grades, reflecting the growing domestic demand for such products. At end-January, Japan held a total of around 473.05 million barrels of petroleum reserves, equating to 236 days of domestic consumption, comprising national petroleum reserves, oil reserves held by the private sector and a joint crude oil storage program with oil-producing countries, according to METI data. Crude stocks in the national oil reserves accounted for 285.99 million barrels of the total while oil products in the national reserves comprised another 8.99 million barrels. Privately held crude reserves totaled 74.03 million barrels, with oil products stocks at 97.74 million barrels, while 6.29 million barrels were held by oil producers in Japan.

Chinese refineries will slash throughput in April and lift oil product exports from initial plans to compensate for falling domestic demand due to COVID-19 lockdowns. As a result, 10 refiners from the 11 polled Sinopec and PetroChina refining sources said they have cut their April throughput by 30,000-100,000 mt from their initial planned volumes or plan to reduce. These include Sinopec's 14 million mt/year Shanghai Petrochemical, which has been locked down since late March. It will lower throughput by 40,000 mt to 1.19 million mt in April. The neighboring 8 million mt/year Anqing Petrochemical plant has trimmed throughput several times since April 1 to get the current target of about 550,000 mt from an initial 650,000 mt. Another neighbor, the 16 million mt/year private greenfield Shenghong Petrochemical has further delayed its startup, with no fixed commission schedule, given high oil prices coupled with weak product demand, according to a company source. Down south in Guangzhou, oil product sales are also slow. The 13.2 million mt/year Sinopec plant has cut throughput by 40,000 mt from planned to 990,000 mt in April. In eastern China's Shandong province, independent refineries have even cut their average utilization rates to 49.4% as of April 6, against 57.1% a month earlier, according to local information provider JLC. In northeast China, three of PetroChina's refineries in Liaoning province have reduced their April throughput by 30,000-50,000 mt from original plans, according to sources with the plants. Meanwhile, Russian crude imports by China's independent refiners slumped 44.4% year on year to a 10-month low of 1.5 million mt in March as a regular buyer ChemChina shut for maintenance its Huaxing Petrochemical. The volume is expected to fall further as a few independent refineries step away from Russian cargoes amid uncertainties in payment and shipping amid the ongoing Russia-Ukraine war and negative refining margins. Japan's largest refiner ENEOS does not plan to sign any Russian crude oil import contracts following Russia's invasion of Ukraine, ENEOS Holdings Chairman Tsutomu Sugimori said March 22. "Following the Ukraine invasion, we have not signed any contracts [for Russian crude]," Sugimori told an online press conference as the president of the Petroleum Association of Japan. "We do not expect to import [Russian crude] for the moment." ENEOS, however, will receive a few ships carrying Russian crude cargoes until April from its purchase contracts signed prior to the invasion in February, Sugimori said. Japan's second largest refiner Idemitsu Kosan has decided to suspend new Russian crude oil trades for imports amid uncertainty over payment and logistics disruptions, a company spokesperson told S&P Global Commodity Insights March 23. Cosmo Oil, Japan's third largest refiner, does not currently procure Russian crude oil, and it does not have any plans to procure the barrels, a Cosmo Energy Holdings spokesperson said March 23. Japanese refiner Taiyo Oil is currently seeking clarity about whether it can continue to lift term crude oil supply from Russia, which it relies on for 20%-30% of its crude procurement, amid uncertainty over payment settlements and shipping, a company spokesperson said April 4. Meanwhile, Japan's Ministry of Economy, Trade and Industry revoked March 31 Taiyo Oil's safety inspection permission at its sole 138,000-b/d Kikuma refinery at Shikoku in western Japan following its violations of safety regulations. Following the revocation, Taiyo Oil will now have to conduct a refinery maintenance program every year and get it approved by the local authorities until the company restores the permission, a METI official said. Prior to the suspension of its safety inspection permission, Taiyo Oil planned to shut two crude distillation units at the Kikuma refinery over May 30-Aug. 17 for a large scheduled maintenance program that takes place every four years. Separately, Japan's largest refiner ENEOS said March 28 it restarted the 170,000 b/d No. 2 crude distillation unit at the Kawasaki refinery in Tokyo Bay on March 25 after it was shut March 16 due to earthquake-led power outages. ENEOS said April 4 that it plans to restart the distillation unit at the Sendai refinery in the northeast and the Chiba refinery in Tokyo Bay in mid-April. At the Sendai refinery, all refining units were shut while all refining units at ENEOS's Chiba Refinery and the No. 2 crude distillation unit at the 247,000 b/d Kawasaki refinery, both in Tokyo Bay, were suspended. In other news, China aims to develop renewables-based hydrogen and curb fossil fuel-based hydrogen production which currently dominates the nation's hydrogen supply, according to its hydrogen industry development plan. The development plan jointly released by China's top economic planner National Development and Reform Commission, or NDRC, and energy regulator National Energy Administration lays out high-level guidelines for its hydrogen supply chain from 2021 to 2035. China has already become the world's largest hydrogen producer with 33 million mt/year of supply, but 63.5% of this is produced from coal, 21.2% as industrial byproduct, 13.8% from natural gas and only 1.5% from water electrolysis that is not fully powered by renewables-based electricity, according to the China Hydrogen Alliance. Quantitative targets are only set up until 2025, including building up 100,000-200,000 mt/year of renewables-based hydrogen production, realizing 1 million-2 million mt/year of CO2 emissions reduction and 50,000 hydrogen fuel cell vehicles or FCEVs by 2025, the report said. By 2030, the plan aims to build up a more comprehensive supply system for clean hydrogen and enable broad applications of hydrogen in different sectors to support China's carbon peaking 2030 target. By 2035, the plan expects to have a more sophisticated ecosystem for hydrogen, covering diverse applications in transportation, energy storage, industrial and other sectors. Renewables-based hydrogen will occupy a significantly increasing share in China's energy consumption mix and become an important backbone for the nation's energy transition, the plan said. NEW AND ONGOING MAINTENANCE Refinery Capacity b/d Country Owner Unit Duration Negishi 270,000 Japan ENEOS Part Closure'22 Wakayama 127,500 Japan ENEOS Full Closure'23 Kikuma 138,000 Japan Taiyo Oil Full May Hainan 184,000 China Sinopec Full Mar Jinzhou 150,000 China Petrochina Full Apr Yangtz 290,000 China Sinopec Full Mar Tahe 100,000 China Sinopec Full Mar Huaxing 140,000 China ChemChina Full Apr UPGRADES Zhenhai 230,000 China Sinopec Expansion NA Jinling 420,000 China Sinopec Upgrade NA Haiyou 70,000 China Haiyou Upgrade On hold Huizhou 440,000 China CNOOC Upgrade NA Chiba 190,000 Japan Idemitsu Upgrade 2020 Changling 230,000 China Sinopec Upgrade NA Qinzhou 240,000 China Guanxi Upgrade 2023 Fujian 280,000 China Sinopec Upgrade NA LAUNCHES Tangshang 300,000 China Xuyang Group Launch 2021 Jieyang 400,000 China Guandong Launch 2021 Huajin Aramco 300,000 China Joint Launch 2024 Lianyungang 320,000 China Shenghong Launch Launched Yulong 400,000 China Yulong Launch 2022 Near-term maintenance New and revised entries Japan ** Japan's Cosmo Oil shut one of two crude distillation units at its 177,000 b/d Chiba refinery in Tokyo Bay after a fire at a furnace April 2, a company spokesperson said April 5. The fire broke out at around 6:15 pm local time (0915 GMT.) April 2, and the local fire department confirmed that it was put out at 11:45 pm, the spokesperson said. No one was injured, and it was not clear when Cosmo would be able to resume the CDU, the spokesperson said. China ** PetroChina's Yunnan Petrochemical refinery in southwestern Yunnan province, which shut its 4 million mt/year residual hydrogenation unit and some of its relative downstream facilities due to a blast in December, is fully back online. ** ChemChina has shut for maintenance its Huaxing Petrochemical. Works started on March 15. Existing entries China ** Sinopec Hainan plans to completely shut for nearly two months of scheduled maintenance March 15-May 10, and there will no oil products exports in April. The Hainan refinery plans to process 370,000 mt of crude oil in March, which would be equivalent to about 47% of its nameplate processing capacity, down from 102% in February. ** PetroChina's Liaohe Petrochemical will shut for maintenance over April-June. ** Sinopec's Yangtz Petrochemical is scheduled to shut the entire refinery for maintenance over March-April. ** Sinopec's Tahe Petrochemical is scheduled to shut for maintenance from mid-March to late April. Japan ** Japanese refiner Taiyo Oil plans to shut two crude distillation units at its sole Kikuma refinery over May 30-Aug. 17 for scheduled maintenance, a company spokesperson said March 8. It will halt a 106,000 b/d No. 1 CDU and a 32,000 b/d No. 2 CDU. "This will be a large-scale planned maintenance [which is done] every four years, and we plan to shut the No.1, the No. 2 CDUs and the [32,000 b/d] RFCC at about the same time," the spokesperson said. ** Japan's largest refiner ENEOS will decommission the sole 127,500 b/d crude distillation unit at its Wakayama refinery in western Japan in October 2023. ** Japan's ENEOS will decommission the 120,000 b/d No. 1 CDU at its 270,000 b/d Negishi refinery in Tokyo Bay in October 2022. It will also decommission secondary units attached to the No. 1 CDU, including a vacuum distillation unit and fluid catalytic cracker. ENEOS will also decommission a 270,000 mt/year lubricant output unit at the Negishi refinery. Upgrades Existing entries ** Sinopec plans to add a petrochemical plant to its Fujian refining complex as part of its phase two expansion plans, according to a company source. "An ethylene plant will likely be added," said the source, without giving more details as the plans are still in early stage. The adding of the new chemical plant, will likely help lift the overall run rates at the refinery, sources said. On March. 8, Saudi Aramco and Sinopec said they would study possible capacity expansion at the Fujian refinery. The two companies will undertake a feasibility study looking into "optimization and expansion of capacity", Saudi Aramco said in a statement. ** Chinese Sinopec's refinery Zhenhai Refining and Chemical has a 27 million mt/year refining capacity and a 2.2 million mt/year ethylene plant, after its phase 1 expansion project of 4 million mt/year crude distillation unit and a 1.2 million mt/year ethylene unit was delivered end-June. The company aims to grow its refining capacity to 60 million mt/year and 7 million mt/year of ethylene by 2030. ** PetroChina's Guangxi Petrochemical in southern Guangxi province planned to start construction at its upgrading projects at the end of 2021, with the works set to take 36 months. The projects include upgrading the existing refining units as well as setting up new petrochemical facilities, which will turn the refinery into a refining and petrochemical complex. The project will focus on upgrading two existing units: the 2.2 million mt/year wax oil hydrocracker and the 2.4 million mt/year gasoil hydrogenation refining unit. For the petrochemicals part, around 11 main units will be constructed, which include a 1.2 million mt/year ethylene cracker. ** Sinopec's Changling Petrochemical in central Hunan province plans to start construction for its newly approved 1 million mt/year reformer. ** Japan's Idemitsu Kosan plans to start work on raising the residue cracking capacity at its 45,000 b/d FCC at Chiba. ** Axens said its Paramax technology has been selected by state-owned China National Offshore Oil Corp. for the petrochemical expansion at the plant. The project aims at increasing the high-purity aromatics production capacity to 3 million mt/year. The new aromatics complex will produce 1.5 million mt/year of paraxylene in a single train. ** Construction of a new 1 million mt/year coker at Chinese independent refinery Haiyou Petrochemical, in eastern Shandong, has been put on hold. ** Sinopec's Jinling Petrochemical refinery in eastern China will build a new 600,000 mt/year VDU. Launches New and revised entries ** Private greenfield Shenghong Petrochemical has further delayed its startup, with no fixed commission schedule, given high oil prices coupled with weak product demand. The refinery initially planned to start up in end August, but this was postponed to end-December and then to January. ** PetroChina has started constructing a low sulfur bunker fuel oil project with 2.6 million mt/year production capacity at its upcoming Guangdong Petrochemical. PetroChina targets to commission Guangdong Petrochemical by end-2022. The Guangdong plant is PetroChina's latest greenfield integrated refinery in southern China Jieyang city, featured with a 2.6 million mt/year aromatics unit and a 1.2 million mt/year steam cracker. Existing entries ** Saudi Aramco said it has "taken the final investment decision" to participate in the development of a major refinery and petrochemical complex in China which is expected to be operational in 2024. The complex will be developed by Huajin Aramco Petrochemical Company (HAPCO), a joint venture between Aramco, North Huajin Chemical Industries Group Corporation and Panjin Xincheng Industrial Group. The decision is subject to finalization of transaction documentation, regulatory approvals and closing conditions. The project represents an opportunity for Aramco to supply up to 210,000 b/d of crude feedstock for the complex. The complex involves a 300,000 b/d refinery, 1.5 million mt/year ethylene-based steam cracker and a 1.3 million mt/year PX unit, S&P Global Commodity Insights has reported previously. ** Honeywell said China's Shandong Yulong Petrochemical will use "advanced platforming and aromatics technologies" from Honeywell UOP at its integrated petrochemical complex. The complex will include a UOP naphtha Unionfining unit, CCR Platforming technology to convert naphtha into high-octane gasoline and aromatics, Isomar isomerization technology. When completed Yulong plans to produce 3 million mt/year of mixed aromatics. Shandong's independent greenfield refining complex, Yulong Petrochemical announced the start of construction work at Yulong Island in Yantai city at the end of October 2020. Construction was expected to be completed in 24 months. The complex has been set up with the aim of consolidating the outdated capacities in Shandong province. A total of 10 independent refineries, with a total capacity of 27.5 million mt/year, will be mothballed over the next three years. Jinshi Petrochemical, Yuhuang Petrochemical and Zhonghai Fine Chemical, Yuhuang Petrochemical and Zhonghai Fine Chemical will be dismantled, while Jinshi Asphalt has already finished dismantling. ** China's coal chemical producer Xuyang Group has announced plans to build a greenfield 15 million mt/year refining and petrochemical complex in Tangshang in central Hebei province.

The Singapore low sulfur fuel oil supply is expected to remain tight in the April 11-15 trading week as higher gasoil crack spread continuously draws LSFO blending components to the middle distillate market. The high sulfur fuel oil market is also likely to stay strong in the week due to a decline in an inflow of the Middle Eastern cargoes into Asia after the Russia-Ukraine conflict. Crude oil futures opened lower in Asia April 11, with June ICE Brent trading at $100.47/b at 0300 GMT, down $1.11/b from the 0830 GMT Asian close April 8. Marine Fuel 0.5%S ** Singapore Marine Fuel 0.5%S May-June swap spread weakened in April from March. The front-end time spread averaged $21.29/mt over April 1-8, down from $30.42/mt in March, S&P Global Commodity Insights data showed. Market sources said supply would stay tight despite weaker time spread as sulfur and viscosity cutter stocks, such as vacuum gasoil and light cycle oil are taken by the gasoil market as the gasoil crack spread has been strong, fuel oil traders said. The time spread has weakened following Brent swaps while the front-end May-June spread averaged $1.27/b over April 1-8, down from $3.33/b in March. ** Market optimism in the downstream bunker market stemmed from a less-than-ample availability of finished grade product, especially for delivery on a prompt basis; only a few suppliers were still in a position to offer product to the spot market for delivery less than around 10 days, traders said. ** The delivered market was pricing higher on account of a rising replacement cost for bunker sellers due to a firming upstream market, traders said. The premium for Singapore-delivered marine fuel 0.5%S bunker over the benchmark upstream Singapore marine fuel 0.5% cargo assessment averaged $29.92/mt in the week ended April 8, up from the previous week's average of $23.65/mt, S&P Global data showed. ** Market volatility is still likely to cap demand for Singapore-delivered marine fuel 0.5%S, whereas stockpiles in the downstream market was heard balanced against demand, according to local bunker suppliers. ** In Fujairah, a tight prompt availability situation coupled with limited slots available for scheduling barge delivery of IMO-compliant product on a prompt basis to the spot market was likely to help set a floor for Fujairah-delivered marine fuel 0.5%S bunker premium. ** Uptick in LSFO bunker demand is likely to drawdown inventories at the port of Hong Kong for the rest of April, following the easing of quarantine measures for bunker-only calls since April 1, bunker suppliers said. ** Traders anticipate LSFO bunker inventory shortfalls in Japan to prolong despite the resumption of loadings for smaller parcels expected during the week started April 11 at Idemitsu and ENEOS refineries. ** Steady downstream demand for Zhoushan-delivered marine fuel 0.5%S amid limited availability of the ex-wharf grade is expected to buoy premiums, according to market sources. High Sulfur Fuel Oil ** Both 180 CST and 380 CST grades are expected to remain tight as US refiners increasingly take HSFO from the Middle East as they are no longer buying Russian fuel oil. ** The 180 CST grade is tight in particular as demand from South Asia has been surging. As a result, the Singapore 180 CST cash differential to MOPS strip rose to $31.66/mt on April 8, the highest since Nov. 5, 2019, when it stood at $34.66/mt, S&P Global data showed. The 180 CST-380 CST spread hit an all-time high for three days in a row to rise to $56.75/mt on April 8, S&P Global data showed. ** The prevailing concerns around contaminated fuel at the city-state were also limiting the number of suppliers to source the product from, bunker traders said. Tight prompt availability has meant that the earliest that most suppliers are able to offer product to the spot market is around 10 days forward. ** This in turn was likely to have a cascading effect on Singapore-delivered 380 CST high sulfur bunker premium, which has indeed sky-rocketed in the recent days. The premium for Singapore-delivered 380 CST high sulfur bunker over Singapore 380 CST HSFO cargo, which averaged $33.88/mt in the week ended April 8, was up from the previous week's average of $23.83/mt, and stood at a near two-year high $36.67/mt on April 8, S&P Global data showed. ** Amid above-average volumes of fixtures since April, bunker suppliers expect rising upstream availability of HSFO cargoes in Hong Kong to supply the strengthening downstream demand. ** The recent diversion of inquiries for delivered HSFO to South Korea is expected to lift bunker demand while stockpiles remain ample, as buyers were heard skipping bunker-only calls in Singapore amid quality concerns.

War-torn Ukraine is increasingly reliant on fuel supplies via truck from Poland following the destruction of up to 20 major fuel depots, damage to its main refinery, and the cutting of Black Sea shipping routes, Ukrainian experts say. Russia's military assault on northern Ukraine has abated in recent days, but as the focus of military activity shifts to the east, the country faces increasingly stretched fuel supply, Serhiy Kuyun, head of the A-95 fuel consultancy, told S&P Global Commodity Insights. Ukraine has long been shifting away from Russian energy and previously took Azeri crude by sea for the Kremenchuk refinery and diesel from northern neighbor Belarus. It also hosts the Odesa-Brody pipeline from the Black Sea into Central Europe. But the Russian invasion meant cutting supplies from Belarus, which has supported Moscow, and Black Sea security risks and a Russian blockade have stopped shipments from Azerbaijan and Romania, the latter previously a source of fuel supply by sea. With crucial infrastructure now damaged and the geography of the Carpathian Mountains preventing supply from other neighbors, Ukraine is now largely dependent on Poland; the latter is in the process of merging its two main refineries under PKN Orlen, which also operates Lithuania's Mazeikiai. "The market has not stopped, but it has been forced to adapt," Kuyun commented in a statement. "There are no stocks of fuel anymore. We're selling as soon as fuel tanker truck arrives." In the course of March, Russia's navy targeted fuel depots across the country, including in Lviv, Lutsk, Ternopil, Rivne, Zhytomyr, Odesa, Poltava, Kyiv, Chernihiv, Kharkiv and Dnipro. Then on April 2 the 240,000 b/d Kremenchuk refinery was badly damaged in a Russian missile attack, putting it out of action, according to regional and company officials. Ukraine's second refinery, the Shebelinka Gas Processing Plant in the east of the country, was taken offline Feb. 26 due to the threat of shelling. Kuyun added that the stricken fuel depots were mostly full early in March, with later attacks coming when stores were already depleted. The country now faces not only a shortage of fuel, but a squeeze on trucks available for bringing in fuel, he said. "More fuel trucks are needed that can bring fuel directly from abroad," Kuyun said. "It is necessary that every owner of a fuel tanker truck has the opportunity to go and buy fuel." Ukraine's government is also liaising with state railroad company Ukrzaliznytsia to make sure supplies can also come by rail. Price liberalization Kuyun advised the government should cancel price controls and lift restrictions on maximum gasoline and diesel retail prices to encourage private traders to import more. "I know of three regional fuel chains that have already stopped selling fuel in the last two days because the cost is higher than the set prices," he said. "Even large players are forced to limit sales, because new batches of fuel arrive at the pump, but its cost is already beyond the established price corridor." The Ukrainian parliament on March 15 cancelled excise tax on all kinds of fuel and lowered VAT to 7% from 20% on imports of gasoline and diesel fuel. The lower taxes create an incentive for private fuel suppliers to arrange more supplies and help to reduce prices at retail stations. The government also ordered the state customs service to remove bureaucracy from customs clearing of fuel imports. Planting season While the turmoil of war and a flow of refugees out of the country will have impacted demand, the lack of refining capacity also poses a challenge for the vital grain sowing season — Ukraine being an important source for global grain markets. Ukraine is likely to reduce the area planted with grain crops by up to 30% because of fighting in eastern and southern regions, in turn reducing the demand for fuel, according to the government. In 2021, Ukraine imported 8.79 million mt of petroleum products, up 9.6% from 8.02 million mt in 2020, according to the state customs service.

Refineries in Russia and Belarus are reducing throughput, with some halting production, as they have been unable to place their output due to the reluctance of international buyers to take Russian-origin cargoes following Moscow's invasion of Ukraine. According to estimates by market participants, around 4 million mt of capacity has been shut since Feb. 24, the day Russia invaded Ukraine. Russian refiners typically process around 25 million mt/month (around 5.9 million b/d). Russian Deputy Prime Minister Alexander Novak said April 7 that Russia's oil output in April could fall 4%-5% month on month due to financial and logistical difficulties. Novak, who was speaking to Russia 24 TV channel, also said there would also be "adjustments to refining, there will also be a decrease in refining volumes," adding that he did not expect this to affect domestic supplies, and exports would continue. Some of the lower throughput is due to planned spring turnarounds, though in addition to those, a host of plants appear to have brought forward their works and extended them through June. The maintenance schedule is encompassing a growing number of plants, including those in the key Samara and Ufa refinery hubs in central Russia and the Far East, and will involve both primary and secondary units. Small and medium-sized refineries, which produce feedstock predominantly for export, are expected to run at around 50% of capacity in April. Others have fully halted their output. At the beginning of March the Tuapse and Novoshakhtinsky plants in southern Russia reduced or fully stopped crude intake, as they were unable to ship production. Tuapse previously exported more than 100,000 mt/month of VGO, but its exports have dropped to zero in April. Despite their previous dependence on Russian vacuum gasoil, many European refineries have taken the decision to self-sanction Russian-origin products in response to the invasion of Ukraine. "There is just no demand for Russian VGO in Northwest Europe," a trader said. Russian fuel oil has faced a similar response from international buyers, with mounting stocks putting pressure on domestic prices and refinery runs. Earlier this week, local media reported that Russian oil major Lukoil was expecting potential refinery closures due to a lack of outlets for fuel oil and spare storage. Later, the company denied the information and said all its refineries were operating normally and finding homes for fuel oil. However, problems placing Russian feedstock products have worsened. Another widely exported Russian feedstock, naphtha, is facing avoidance not only internationally, but from domestic petrochemical buyers, themselves subject to sanctions pressure. The Taif refinery is expected to halt processing this week, as an adjacent petrochemical company has decided to stop taking its naphtha. Petrochemical maker Nizhnekamskneftekhim told local media that its exports to European markets, its main outlet, have dropped since the end of February and individual contracts have been suspended. Belarus plants almost halve throughput The two refineries in Belarus have nearly halved their runs due to sanctions, local media uoted Prime Minister Roman Golovchenko as saying. Naftan currently processes 11,700 mt/day crude oil and Mozyr about 13,700 mt/day. They each have capacity of around 12 million mt/year, although have been processing less than that. While the US and its partners have not imposed additional sanctions on Belarus' oil sector since the invasion, Belarus had already become reliant on Russian ports for its exports, and the ports are now being shunned by much of European industry. Naftan also brought forward its planned maintenance to March after losing some export markets, with Ukraine the main one. Belarus was the biggest source of Ukraine's oil product imports before the war, accounting for 41.9%, but Ukraine halted these after Russia invaded. In 2021, Belarus supplied 3.87 million mt of petroleum products to Ukraine. Currently refineries in Belarus produce enough to supply the domestic market. In the past they had exported oil products, in particular gasoline, to Russia, but Russian refiners themselves are struggling to place their products. Alternative destinations, domestic demand With buyers in the West avoiding Russian products, Moscow is turning to buyers in the East. In addition, exports have been ramped up to neighboring Central Asian countries. Data emerged during the week that Russia increased significantly its oil product exports to China and Kazakhstan in March. Fuel oil represented the bulk of its exports to China, with 394,200 mt supplied, 43.6% higher month on month, while gasoline exports to Kazakhstan increased 32-fold to 7,600 mt. However, gasoline exports to Kazakhstan will not come close to offsetting the potential loss of more than 300,000 mt that Russia previously exported monthly. While Russia traditionally has been short gasoline, the situation appears to be reversing amid an abundance of output countered by diminishing demand. Russian domestic gasoline supply has been rising, as more naphtha is heading into the gasoline pool due to reduced exports and use by petrochemical plants. Meanwhile, market participants are concerned that domestic demand is weak on poor prospects for domestic tourism to southern regions, due to the war in nearby Ukraine. Diesel for the moment appears to be somewhat bucking the pressure of sanctions so far, with fairly typical exports in March, while the April export program from its Baltic port of Primorsk appears to be fairly normal, and domestic demand is drawing support from buying from the agricultural sector and the military. However, there is growing doubt that these diesel flows will find homes in Europe. In March Russia exported around 2.513 million mt of diesel to Europe, but this is currently set to fall to around 452,000 mt in April so far, according to Kpler data.

Asia’s carbon markets are on a trajectory of rapid growth as demand for carbon offsets rises and regional governments work towards net-zero commitments. While turmoil in global energy markets has temporarily shifted attention to energy security, commodity trading hubs like Singapore are pushing ahead with plans to become a carbon trading powerhouse. Eric Yep and Roman Kramarchuk of S&P Global Commodity Insights discuss with Mikkel Larsen , CEO of Climate Impact X, a Singapore-based carbon exchange, on what lies ahead for Asia's carbon markets. More listening options: No content (including ratings, credit-related analyses and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified, reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor's Financial Services LLC or its affiliates (collectively, S&P).

Pakistan has received refusal notices from commodity trader Gunvor to supply four LNG cargoes expected in the next three months, forcing the South Asian country to purchase LNG on the spot market at record-high prices and grapple with energy security concerns, officials at its energy ministry told S&P Global Commodity Insights. Pakistan’s Ministry of Energy received March 26 refusal notices from Gunvor stating that the trader would not be able to ship four LNG cargoes scheduled for delivery on April 15, May 14, June 4 and June 9 as per contracts, officials in Islamabad said. Gunvor declined to comment. Pakistan LNG Ltd., the country’s second-largest state-owned petroleum company that imports LNG on behalf of the government, has a five-year contract with Gunvor at 11.6247% Brent slope that ends in July this year, the officials said. Gunvor has already defaulted on three occasions and backed out from supplying LNG cargoes for the scheduled delivery dates of Nov. 19, 2021, Jan. 10 and March 11, S&P Global reported earlier citing officials. To mitigate the deficit, Pakistan LNG issued two tenders for spot LNG supply where the lowest bidders were Vitol Bahrain at a price of $34.6777/MMBtu for the April 21-22 window, and PetroChina at a price of $33.5300/MMBtu for May 14-15 delivery, tender documents showed. These are some of the highest prices paid by Pakistan for LNG imports and results in downstream prices that make natural gas unaffordable in many sectors. Other bidders for the April 21-22 window were ENOC Singapore offering $37/MMBtu, TotalEnergies at $36.77/MMBtu and PetroChina at $34.99/MMBtu, the document showed. For May 14-15 other bidders were TotalEnergies at $37.77/ MMBtu and PetroChina at $33.53/MMBtu. However, there is a likelihood that the government might not accept even the lowest bids because after adding port handling charges and other costs the imported value of LNG on the day of the arrival might be as much as around $41/MMBtu, according to industry sources. “There is a possibility that two more tenders will be called for the June and July delivery period,” an energy ministry official said. Besides Pakistan LNG, state-owned national oil company Pakistan State Oil is expected to import seven LNG cargoes in April and eight cargoes in May under its long-term contracts with Qatar. The two long-term agreements with Qatar -- for 15 and 10 years, respectively at Brent slopes of 13.37% and 10.2% each -- end in 2031 and 2032. Pakistan’s LNG imports for the eight months of the fiscal year ended Feb. 28 amounted to $3.078 billion, nearly double $1.499 billion over the same period in the previous fiscal year, data from Pakistan Bureau of Statistics showed. Pakistan LNG also has a 15-year LNG contract with Italian gas company Eni under which LNG was priced at a Brent slope of 11.624% in the first two years, after which the Brent slope rose to 11.95% for the next two years. From the fifth year onwards, LNG was priced at 12.14% of Brent with the contract expiring in November 2032. Supplier defaults Pakistan has been facing supply issues under its agreements with both Eni and Gunvor. Pakistan LNG had received refusal notices for March cargoes from both Eni and Gunvor, forcing it to issue emergency tenders Feb. 17 for delivery in March 2-3 and March 10-11, officials said. There were no bids for the March 2-3 window, and two bids for March 10-11 from Qatar Petroleum at $25.12/MMBtu and ENOC at $26.125/MMBtu, out of which Qatar’s bid was awarded, according to bid documents. The March cargo was Eni’s fourth cancellation. It previously defaulted in January 2021, August 2021 and November 2021, the energy ministry official said, adding that Gunvor has always sought force majeure to avoid paying the penalty for non delivery. Eni did not immediately respond to queries about the March cancellation. It previously attributed the 2021 cancellations to “a disruption in the LNG supply chain originated by a third-party supplier.” The cancellations have raised concerns about energy security and the Pakistan government intends to impose a penalty of 30% of the price of the term cargo, as well as challenge the force majeure declaration, the official said. The government has had to take measures to absorb the impact of gas shortages, such as providing subsidies to textile and related industries of Pakistan Rupee 40 billion ($12.2 million) to be paid during January to March. The share of electricity produced from regasified LNG (RLNG) has also fallen sharply due to high prices with January 2022 electricity production from RLNG falling as much as 32%. In the seven months ended Jan. 31, electricity production from RLNG power plants shrank by 8%, government data showed. This version corrects Gunvor's name in the text of the story.