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

Russia has long supplied European and US markets with fuel oil. In light of the war in Ukraine, where is this fuel going and how can the usual buyers make up the shortfall? S&P Global Commodity Insights reporters David Petutschnig and Chloe Davies discuss with Joel Hanley how the dynamics of high sulfur fuel oil and vacuum gasoil are changing fast. Explore our special report Inside Fujairah: A gateway for energy and commodities in the Middle East 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).

In this episode of the Oil Markets Podcast, senior editor Emma Kettley and associate editor David Lewis discuss with Paul Hickin the recent changes in crude flows and how Russian crude finds its way in new markets. Our experts explain the changing trade patterns in Europe where participants shun Russian barrels, which surprisingly didn’t prevent Urals exports to reach three-year highs in May. Tell us more about your podcast preferences so we can keep improving our shows. Take our two-minute survey here: https://bit.ly/plattspod22 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).

Alberta Premier Jason Kenney recently made the rounds in Washington, talking to lawmakers and State Department officials about the role Canada, and specifically Alberta’s oil sands, can play in ensuring North American energy security and easing American drivers’ pain at the pump. And his frustration with the lack of proactive outreach by the Biden administration to Alberta, which accounts for over 60% of US oil and gas imports, was clear. Kenney joined senior editor Jasmin Melvin on the podcast to share his concerns and hopes for future collaboration between the US and Canada. He discussed Alberta’s ability to increase its crude exports to the US as well as federal policies in Canada and the US that he worries will inhibit resource development. Stick around after the interview for Jordan Blum with the Market Minute, a look at near-term oil market drivers. This podcast was produced by Jasmin Melvin in Washington and Jennifer Pedrick in Houston. Related content: Biden's energy policies seen jeopardizing prospects for a North American energy alliance Biden administration mum on plans to ease Venezuelan oil restrictions; lawmakers speak out Feature: Ample Canadian crude pipeline, rail export capacity exists if output rises 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).

OPEC and Russia remain aligned but the Kremlin's influence within the group of major oil producers looks diminished by sanctions and the international backlash to its war in Ukraine. As the OPEC+ alliance prepares to hold its next virtual meeting May 5 to decide on June crude output levels, Russian production is already on the decline, and its exports will be further hit by an EU ban aimed at choking off the Kremlin's income from crude. Meanwhile, Saudi Arabia and the major Arab producers in OPEC are coming under intense pressure from the US to sever links with President Vladimir Putin's regime. "Russia's formerly pivotal role within OPEC+ policymaking is now less certain, ahead of anticipated export dislocations and production shut-ins, but market dynamics had already reduced the importance of formal OPEC+ decisions compared to the past two years," S&P Global Commodity Insights' chief geopolitical adviser Paul Sheldon said. Two months into the conflict, Saudi and the rest of OPEC continue to stand by their alliance with Russia, despite intense lobbying by US President Joe Biden to pump more oil and ease higher prices caused by the conflict. However, from the oil market perspective, Moscow's usefulness in managing crude supply is already much diminished. OPEC+ production targets, which have been gradually raised as the worst economic impacts of the pandemic have worn off, are above many members' sustainable production capacities. The alliance is set to approve another 432,000 b/d hike in quotas at its May 5 meeting but likely will not come close to fulfilling it. Russia is almost certain to contribute to the growing OPEC+ supply gap, with its production falling to 10.04 million b/d in March, well below its quota of 10.331 million b/d, according to the latest Platts survey by S&P Global of the group's output. That is still a sizeable 23.6% of overall OPEC+ production, but it is set to shrink further. Preliminary S&P Global estimates of Russian production for April indicate a decline of as much as 1 million b/d from March, and ratcheting western sanctions combined with the EU ban on Russian oil imports are expected to see some 3 million b/d shut in by August. Shaky alliance For now, OPEC+ members say there is no need to abandon their ally, foreseeing a time in the oil market after the war has ended when Russia's clout might be needed. Gabriel Obiang Lima, hydrocarbons minister of OPEC member Equatorial Guinea, said it was important for the organization to stay in dialogue with Russia and align priorities as major producers, rather than break ties. "Any country has a voluntary decision to join OPEC+ or not," he said on a webinar with reporters. "Geopolitics, we can’t control. It is not for us to judge if we can work with a third party. We do not decide how much they produce, who they supply to. What is important for OPEC+ is that we share information." However, it is a position that may become harder to defend if the conflict in Ukraine drags on for years, or escalates to draw in other nations. In terms of market fundamentals, Russia's participation has helped OPEC restore its credibility. The group's market share had been declining for years with the growth of US shale and other non-OPEC production, prompting the bloc to join forces with Russia and nine other allies in 2017 to form their current coalition that now controls about half of global output capacity. Analysis by the OPEC secretariat prepared for the group's meeting and seen by S&P Global indicates that slowing demand growth and the US-led release of strategic oil stocks by several consuming nations will lead to a 1.9 million b/d supply surplus for the year. The analysis assumes the OPEC+ alliance will continue raising its quotas by 432,000 b/d each month until October, as planned, but does not model in any loss of Russian production from sanctions, which could eat up that surplus. War impact Despite higher oil and gas revenues the war will prove costly long-term for Russia's finances and ultimately will see it lose market share for its hydrocarbon exports. At the start of 2022, S&P Global estimated fiscal breakeven oil prices for both Russia and Saudi Arabia at $65/b. Russia's is undoubtedly higher now, due to expected losses of exports, as well as the extreme price discounts that Russian companies have had to absorb in order to entice buyers given the threat of sanctions. S&P Global assessed key Russian crude grade Urals at $71.48/b, compared to global benchmark Dated Brent at $106.125/b on May 3. For comparison, Urals was assessed at $90.72/b and Dated Brent at $100.48/b on Feb. 23, the day before Russia invaded Ukraine. Asian customers are lapping up the Russian discounts, putting Russia in direct competition with OPEC's core Gulf members in their key market. Discounts on Urals have led to a significant drop in Russia's oil revenues -- a major contributor to the state budget. George Voloshin, head of the Paris branch of Aperio Intelligence, estimates that oil revenues have fallen to around $380 million/day, down about 11% since late 2021 when they averaged around $415 million to $430 million/day. "The shock will be very painful going forward. Russia will be running high government budget deficits and depleting its FX reserves," he said. Growing shut-ins, the risk of harsher sanctions and OPEC+ policy will determine Russian oil output levels and the health of its economy in the coming months. For OPEC ministers, who have been urging a diplomatic resolution to the war and decrying western military aid to Ukraine, a recovered Russian oil sector is vital to the staying power of the alliance, which will have to confront the energy transition while meeting post-pandemic energy demand. Ultimately, a prolonged war could force a reassessment of OPEC's ties with Russia. (Update: Adds comment from Equatorial Guinea minister, appends updated infographic)

Crude oil from the largest-ever drawdown of the US Strategic Petroleum Reserve starts hitting the market this month and will continue flowing through October. The release of 180 million barrels in response to the war in Ukraine curbed oil price outlooks as refiners sought to replace Russian supplies. Use this interactive tool to see how crude and fuel prices have reacted to past SPR drawdowns. Related content: Latest SPR buyers pay average $105.60/b, reflecting high oil price expectations US President Biden announces 1 million b/d SPR crude release for six months Valero, Motiva, ExxonMobil take largest shares of US SPR's May-June sale

High and volatile oil prices exacerbated by the Russia-Ukraine crisis are raising questions as to when and if it will lead to demand destruction and renewed investment in the energy sector. Jeff Currie, head of commodity research at Goldman Sachs , talks to associate director Paul Hickin about the infancy of what he has been calling a new commodity supercycle and the supply challenges ahead. 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).

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.