Are Oil Prices Set For A Comeback?
Oil prices have given up in recent weeks all the gains they had made since the Russian invasion of Ukraine as market fears of recession intensified. There are signs of slowing economic growth, which could dent oil demand. But oil market participants and analysts are struggling to estimate how much demand could suffer in a recession that will be nothing like the 2008/2009 credit collapse and crisis. Bearish factors are dominating current market sentiment, but some analysts say that paper traders may have already priced in too much fear of recession. At the same time, the U.S. labor market is outperforming expectations, defying other gloomy signals that America’s economy is slowing. Moreover, annual inflation in the U.S. in July eased from the previous month due to lower gasoline prices. Still, bearish sentiment currently prevails on the oil market, as participants are paying more attention to recession fears, the steady Russian oil exports contrary to early expectations of massive losses in the region of 3 million bpd, and weaker Chinese factory activity and snap COVID-related lockdowns weighing on fuel demand. Imminent bullish signals include the hurricane season in the United States this month and next, where severe storms and hurricanes could force shut-ins at Gulf of Mexico production platforms or preemptive shut-ins at refineries along the Gulf Coast. Another bullish factor by the end of the year could emerge from the end of the U.S. SPR releases, currently expected to end in October. At the same time, U.S. oil producers are not boosting output too much—even at $100 oil—due to continued capital discipline, supply chain constraints, and cost inflation. The full effect of the EU ban on imports of Russian seaborne oil, expected to kick in at the end of the year, is also challenging to estimate, as is the impact of a possible price cap on Russian oil, which would allow insurance and other services for Russia’s crude if buyers commit to buy it at or below a certain price. Recession Fears The oil market, however, is currently in the grip of concerns about a global recession and demand destruction. Recession fears in Europe have intensified amid the sky-rocketing energy prices and low supply of Russian pipeline gas which is forcing companies in some energy-intensive industries to curtail production. In the UK, the Bank of England warned last week that the country is expected to enter a recession from the fourth quarter of this year, which will last until the end of 2023. The net long speculative positions—the difference between bullish and bearish bets—in Brent and WTI had dropped to a very low level as of early August due to fears of a recession and softening global economic growth, SEB bank said in a research note earlier this week. The physical crude market is also losing steam due to fears of an economic slowdown or recessions, traders told Reuters this week. “The market is very bearish at this moment. No one is in a hurry to buy,” a trader based in Singapore told Reuters. Yet, the labor market in the U.S. remains strong, and the latest employment data far exceeded analyst estimates. Total nonfarm payroll employment rose by 528,000 in July, and the unemployment rate edged down to 3.5%, the U.S. Bureau of Labor Statistics said last week. The numbers smashed Dow Jones estimates of 258,000 job additions and a 3.6% unemployment rate. “The report throws cold water on a significant cooling in labor demand, but it’s a good sign for the broader U.S. economy and worker,” Michael Gapen, an economist at Bank of America, said in a note cited by CNBC. Some analysts say the 9% drop in WTI Crude futures last week was exaggerated, and the economic concerns could be overblown. Caroline Bain, chief commodities economist at Capital Economics in London, told Houston Chronicle: “The big picture,” she said, “is that the market could be pricing in too much recession fear.” The near-term oil price movement will be led by the economic picture, inflation, and interest rate hikes, but some bullish factors could tip the sentiment back to rallying prices. These include very low global spare capacity, OPEC+’s inability to pump much more than it is producing now, and the wild card Russia and its standoff with the West. It will become clearer in the coming months how Russian supply to the markets could be affected and whether Putin will simply stop selling oil to those countries who join a potential price cap on Russian oil. The proposed price cap includes allowing insurance and other services for Russia’s oil shipment, but Moscow has already said it would not export its oil if the price cap is set below its cost of production. While some analysts say that oil is headed even lower with recessions looming, others say this recession could be different and not lead to an actual drop in oil demand year over year. Goldman Sachs, for example, revised down its Brent price forecast for this quarter to $110 a barrel, down from a previous projection of $140 per barrel, but it still believes the case for higher oil prices remains strong. “We believe that the case for higher oil prices remains strong, even assuming all these negative shocks play out, with the market remaining in a larger deficit than we expected in recent months,” Goldman Sachs’s strategists wrote in the note this week carried by Bloomberg.
Are Iraq’s Ambitious Oil Production Goals Feasible?
Iraq is planning to increase its crude oil production to phased targets of 5 to 8 million barrels per day (bpd) over time, according to the first vice president of the Iraq National Oil Company (INOC), Hamid Younis, last week. The director general of the Iraq Oil Exploration Company (IOEC), Ali Jassim, added that the next phase will see “remarkable activity” in the exploration sector, including operations in the Western Desert and the Nineveh governorate. Given the current delicate supply-demand balance in the global oil pricing matrix, sizeable new supply would go some way to relieving the economic damage being done to many countries by enduring high oil and gas prices, but just how realistic are these statements on higher oil volumes from Iraq? In broad terms, the statements are entirely realistic, with Iraq holding a very conservatively estimated 145 billion barrels of proven crude oil reserves (nearly 18 percent of the Middle East’s total, around 9 percent of the globe’s, and the fifth largest in the world). However, according to the International Energy Agency (IEA) in its 2012 report on the country, the extent of Iraq’s ultimately recoverable oil resources is subject to a large degree of uncertainty and may well turn out to be a lot more. Much of the earlier data that fed into the 145 billion barrels reserves figure was derived from the United States Geological Survey (USGS) 2000 assessment and, using this data, the IEA’s 2012 analysis put the level of ultimately recoverable crude and natural gas liquids resources in Iraq at around 232 billion barrels. As at the end of 2011, only 35 billion barrels of that 232 billion figure had been produced. Having said this, as the IEA itself pointed out, there are other estimates from reliable sources that Iraq’s undiscovered oil resources are considerably higher even than the IEA’s figures. When Iraq’s Ministry of Oil came up with its own crude oil reserves figure of 143 billion barrels in 2010 – before it was upgraded to 145 billion barrels two years later – the Ministry stated that Iraq’s undiscovered resources amounted to around 215 billion barrels. Moreover, said the IEA, a detailed study by Petrolog, published in 1997, reached a similar figure but even this did not include within this 215-billion-barrel figure, crude oil resources in the parts of northern Iraq under the administration of the government of the semi-autonomous region of Kurdistan (the KRG). Back in 2012, and even using the more conservative USGS figure, Iraq had produced only 15 percent of its ultimately recoverable resources, compared with 23 percent for the Middle East as a whole, according to the IEA, and the Agency expected exploration efforts to add substantially to proven reserves in the future. Moreover, drilling in Iraq has long had an exceptionally high success rate: of 530 potential hydrocarbon-bearing geological prospects identified by geophysical means in Iraq as of the time of the 2012 IEA report, only 113 had been drilled, with oil having been found in 73 of them. The IEA also noted that prior to the then-recent surge in exploration activity in the KRG area, more than half of the exploratory wells in Iraq had been drilled prior to 1962, a time when technical limits and a low oil price gave a much tighter definition of a commercially successful well than would be the case today. It is apposite to note at this point, however, that it is one thing to have huge levels of reserves and recoverable resources, but it is quite another to drill them and export them, and over the period from when the IEA report was produced in 2012 to now, crude oil production in Iraq has risen from just over 3 million bpd to just over 4 million bpd only. It could be said that this is an impressive 25 percent rise, but in absolute terms, it ranks as an extremely poor return on the crude oil resources that Iraq has, particularly when factoring in how easy its oil is to recover, as evidenced by the country’s crude oil having the lowest lifting cost in the world of US$1-2 per barrel, alongside the crude oil of Saudi Arabia and Iran. In contrast to actual oil production figures, in 2013 Iraq launched its ‘Integrated National Energy Strategy’ (INES), which formulated the three forward oil production profiles for Iraq, as analyzed in depth in my latest book on the global oil markets. The INES’ best-case scenario was for crude oil production capacity to increase to 13 million bpd (at that point by 2017), peaking at around that level until 2023, and finally gradually declining to around 10 million bpd over a long period thereafter. The mid-range production scenario was for Iraq to reach 9 million bpd (at that point by 2020), and the worst-case INES scenario was for production to reach 6 million bpd (at that point by 2020). These different crude oil output trajectories were also in line with those laid out in the IEA’s 2012 report. Specifically, in the IEA’s ‘Central Scenario’ of 2012, Iraq’s oil production increased to more than 6 million bpd (by 2020), and then 8.3 million bpd by 2035. In the IEA’s ‘High Case’, crude oil production would surpass 9 million bpd in 2020 and then rise to 10.5 million bpd in 2035. The foundation for Iraq to achieve these massive increases in crude oil production is, therefore, absolutely solid. So, why has it not done so yet? There are two basic reasons for this, both of which – and other tangential reasons – are analyzed in full in my latest book: the first being the endemic corruption that has plagued the Iraq oil sector, particularly since the fall of Saddam Hussein in 2003, and the second – in part, a function of the first reason but not completely – is the failure to build the Common Seawater Supply Project (CSSP). The culture of corruption in Iraq has been covered in many of my previous articles
IEEFA: High LNG prices affect demand growth in Asia
This is despite the fact that the global LNG industry has pinned its long-term hopes for growth on emerging markets in China, South Asia, and Southeast Asia. “Less than one year into higher prices, LNG markets are already seeing a major realignment of demand away from Asia. Should price spikes and volatility continue over the next several years, downward pressures on Asian LNG demand may accelerate, permanently impairing long-term regional demand growth,” Sam Reynolds, author of the report, said. “Financiers and investors in new LNG projects must take note.” LNG sales in Asia through July 2022 have fallen more than 6% compared to last year. In China and India, two of the largest potential LNG growth markets, LNG imports have fallen 20% and 10% year-over-year, respectively. Demand in Asia could fall further as competition for limited supplies intensifies during the winter heating season. Multiple countries have withdrawn or been forced out of LNG spot markets altogether. Elevated LNG prices bite into demand forecasts High, volatile LNG prices are unlikely to settle for several years due to myriad factors. For example, the threat of continued Russian cuts to European piped gas, outages at LNG liquefaction facilities, and increasingly unpredictable weather events due to climate change could all constrict an already tight global market, according to IEEFA. “Exorbitant prices and unreliability of supply are undermining industry-driven narratives that LNG is a viable ‘bridge fuel’ from coal,” Reynolds added. “Continuous demand growth at persistently high prices will likely prove fiscally unsustainable for emerging markets.” As a result, numerous forecasting agencies have begun cutting estimates for Asia’s medium-term LNG demand growth. The International Energy Agency’s (IEA) latest outlook for gas demand growth in Asia through 2025 is 65 billion cubic meters (cbm) less than its forecast last year. Bloomberg New Energy Finance has cut its expectation for LNG demand in South and Southeast Asia in 2025 by 37 cbm. Other mainstream forecasting agencies, such as Rystad Energy and the Independent Commodity Intelligence Services, have also expressed the risk of permanent reductions in emerging Asia’s LNG demand. Unaffordability of LNG and fuel supply insecurity may cause new import terminals to go unused, potentially costing billions of dollars in stranded assets. As long as unaffordable LNG prices and procurement challenges continue, $96.7 billion dollars of proposed LNG-related infrastructure projects in Pakistan, Bangladesh, Vietnam, and the Philippines will face a heightened risk of underutilization or cancellation. Efforts to reduce LNG dependence are accelerating Many analysts expect Asian demand growth to simply recover to pre-crisis levels once prices settle and new supplies come online. But countries are rapidly developing alternative energy sources that could permanently dent regional LNG demand growth. In China, LNG demand is coming under significant price pressure from new coal and renewables. The country is on pace to deploy 120 gigawatts (GW) of new renewables capacity this year, 40% higher than the previous five-year average. Buyers will reportedly avoid spot market purchases for the rest of the year, while pipeline gas imports were up 60% through April. Moreover, plans to expand pipeline capacity from Russia and Turkmenistan by 100 cbm per year could reduce the need for LNG imports. South Asian countries have tried to maintain LNG import levels when possible, but financially unsustainable prices have led to severe fuel shortages and load shedding. Pakistan and Bangladesh have begun to explore domestic alternatives, including renewables and indigenous gas resources. An uptick in India’s domestic gas production and ambitious renewables targets means that, according to the IEA, annual LNG demand may not surpass 2020 levels through 2025. In prospective LNG markets like Vietnam and the Philippines, LNG import projects are facing delays, while policymakers are increasingly emphasizing the need to reduce dependence on imported fuels. Thailand has faced a perfect storm: high LNG prices, combined with declining domestic gas production and pipeline imports, are causing some of the highest gas and power prices ever. In Northeast Asia, the current LNG market environment has accelerated pre-existing decarbonization plans, breathing new life into renewables deployment and controversial discussions surrounding nuclear power. A renewed focus on energy self-sufficiency in Japan and the election of a pro-nuclear administration in South Korea are expected to have permanent repercussions on LNG demand. “These shifts away from LNG are in their early stages. Should high prices and volatility persist for the next several years, the narrative around LNG as a viable, affordable transition fuel is likely to erode further,” Reynolds concluded. “Ultimately, high prices now may undermine profits and exacerbate stranded asset risks for LNG projects targeting completion later this decade.”
India buys discounted Venezuelan petcoke to replace coal
Indian companies are importing significant volumes of petroleum coke from Venezuela for the first time, trade sources and shipping data show, as the OPEC nation boosts exports not specifically targeted by U.S. sanctions. India’s growing appetite for Venezuela’s petcoke – a byproduct from oil upgrading and an alternative to coal – is being driven by a scramble for inexpensive fuel to power industries as global coal prices have surged. This could boost cash flow for the South American producer, where state and private companies have increased exports of petrochemicals and oil byproducts, and the more competitively-priced Venezuelan supplies could displace cargoes from traditional suppliers. Indian cement companies imported at least four cargoes carrying 160,000 tonnes of petroleum coke from April to June, according to three trade sources, Refinitiv ship tracking data, and Venezuelan shipping schedules. Another 50,000-tonne cargo is expected to reach the port of Mangalore on India’s southwestern coast in the coming days while a 30,000-tonne shipment is scheduled to depart later in August, the data showed. India, which counts the United States and Saudi Arabia as major petcoke suppliers, received its first-ever cargo from Venezuela at the beginning of 2022, according to two of the sources and the documents. A surge in global coal prices to record highs since the Russia-Ukraine war has pushed Indian cement makers including JSW Cement, Ramco Cements Ltd, and Orient Cement Ltd to import pet coke from Venezuela, trade sources said. “The quality of petcoke is very good and it has very low sulfur,” Ramco Cements Chief Financial Officer S. Vaithiyanathan said, adding the downside is that the cargoes take nearly 50 days to arrive in India. Ramco Cements booked two 50,000-tonne cargoes of Venezuelan petcoke, which were delivered in June and July at a discount of $15-20 per tonne to the market price, Vaithiyanathan said. Ramco paid $214.40 and $221 per tonne for the June and July cargoes, respectively, while Orient imported about 28,300 tonnes in April for $220 per tonne, Indian customs documents reviewed by Reuters showed. JSW Cement imported over 30,000 tonnes in June, according to two trade sources, ship tracking data and customs documents. JSW Cement and Orient did not immediately reply to requests for comment. SUPPLIERS The petcoke cargoes were shipped in April-June by Shimsupa GmBH, a Germany-headquartered scrap trading firm, which has an exclusive arrangement with Switzerland-based Maroil Trading to supply Venezuelan petcoke to India, China, Pakistan, and Turkey. “We are exclusive partners of Marfil Trading AG and have all necessary approvals of OFAC and the German government,” Annamalai Subbiah, who owns 100% of Shimsupa, told Reuters. Annamalai confirmed supplying Venezuelan petcoke cargoes for Ramco, Orient, and JSW Cement. The cargoes were shipped from Venezuela’s main oil terminal of Jose, according to the sources and documents. Maroil has in recent years revamped petcoke operations to increase export capacity. Maroil, owned by Venezuela-born shipping magnate Wilmer Ruperti, did not immediately reply to a request for comment. The U.S. Treasury Department, which has so far not targeted Venezuelan exports of petrochemicals and byproducts, declined to comment. Venezuela’s oil sector has been under U.S. sanctions since 2019. Washington imposed sanctions on the country’s most important global business as the former Trump administration ratcheted up its bid to force socialist president Nicolas Maduro out of power.
Centre asks state-run firms to explore plans amid LNG supply crisis: Report
In lieu of securing immediate supplies amid surging gas prices, the central government is exploring a plan involving participatory commitments by state-run energy firms in global liquified natural gas (LNG) contracts available after five years, reported Livemint on Tuesday quoting a top government official. This comes at a time when the prices of LNG have remained high as gas supplies to India have been hit due to the ongoing Russia-Ukraine war. According to Livemint, no-long term global supply contracts will likely be available in the next three years. India currently imports 85 per cent of its oil requirements and 54 per cent of its gas requirements. Supply cuts from Russia have led European nations to corner a bulk of international contracts to stock up for winter. This has resulted in crowding out of Asian buyers, experts said. “In its rush to get rid of dependence on Russian gas supplies, Europe is crowding out Asian buyers, including India, in the LNG market. Prolonged period of depressed prices had postponed FIDs (final investment decisions), leading to lack of long-term supply options in immediate future,” Debasish Mishra, partner at Deloitte, told Livemint. “Indian oil PSUs which have a stake in the Mozambique project should be hopeful as Total has revived the project after violent threats, expecting the first supplies to start by 2024. They may be able to time-swap those contracts,” he added. The concerns over gas supplies also come at a time when India is planning a transition to all clean energy sources, including green hydrogen, which has become an energy security imperative for the nation. India consumed 163.06 million metric standard cu. m per day (mmscmd) in FY22. India’s gas consumption has been rising as nation is focusing to develop a gas-based economy. Gas comprises nearly 6.2 per cent of the nation’s primary energy mix, while the global average stands at 24 per cent. The central government is planning to increase the share of gas to 15 per cent by 2030.