Several refining projects are scheduled in Asia and the Middle East
In Asia and the Middle East, at least nine refinery projects are beginning operations or are scheduled to come online before the end of 2023. At their current planned capacities, they will add 2.9 million barrels per day (b/d) of global refinery capacity once fully operational. In the International Energy Agency’s (IEA) June 2022 Oil Market Report, the IEA expects net global refining capacity to expand by 1.0 million b/d in 2022 and by an additional 1.6 million b/d in 2023. Net capacity additions reflect total new capacity minus capacity that has closed. The scheduled expansions follow a period of reduced global refining capacity. Net global capacity declined in 2021 for the first time in 30 years, according to the IEA. The new refinery projects would increase production of refined products, such as gasoline and diesel, and in turn, they might reduce the current high prices for these products. China’s refinery capacity is scheduled to increase significantly this year. The Shenghong Petrochemical facility in Lianyungang has an estimated capacity of 320,000 b/d, and they report that trial crude oil-processing operations began in May 2022. In addition, PetroChina’s 400,000 b/d Jieyang refinery is expected to come online in the third quarter of 2022. A planned 400,000 b/d Phase II capacity expansion also began operations earlier this year at Zhejiang Petrochemical Corporation’s (ZPC) Rongsheng facility. Outside of China, the 300,000 b/d Malaysian Pengerang refinery (also known as the RAPID refinery) restarted in May 2022 after a fire forced the refinery to shut down in March 2020. In India, the Visakha Refinery is undergoing a major expansion, scheduled to add 135,000 b/d by 2023. New projects in the Middle East are also likely to be an important source of new refining capacity. The 400,000 b/d Jizan refinery in Saudi Arabia reportedly came online in late 2021 and began exporting petroleum products earlier this year. More recently, the 615,000 b/d Al Zour refinery in Kuwait—the largest in the country when it becomes fully operational—began initial operations earlier this year. A new 140,000 b/d refinery is scheduled to come online in Karbala, Iraq, this September, targeting fully operational status by 2023. A new 230,000 b/d refinery is set to come online in Duqm, Oman, likely in early 2023. These estimates do not necessarily include all ongoing refinery capacity expansions. Moreover, many of these projects have already been subject to major delays, and the possibility of partial starts or continued delays related to logistics, construction, labor, finances, political complications, or other factors may cause these projects to come online later than estimated. Although the potential for project complications and cancellations is always a significant risk, these projects could otherwise account for an increase of nearly 3.0 million b/d of new refining capacity by the end of 2023.
Russian state-energy giant Gazprom saw its natural-gas production in July slump to its lowest level since 2008
Russian state-energy giant Gazprom saw its daily natural-gas production slump to its lowest level since 2008, according to a Bloomberg calculation published on Monday. The fall in output came as Russia slowed gas flows to Europe, citing technical challenges arising from sanctions over the Ukraine war. Gazprom’s production in July was 774 million cubic meters a day — 14% lower than in June, according to Bloomberg calculations. The company’s production this year-to-date is 12% lower than the same period in 2021. Overall, Gazprom’s July exports to countries outside the former Soviet Union dropped about a quarter from June, even as daily supply to China increased steadily, per Bloomberg. Europe depends on Russia for 40% of its natural-gas needs, such as cooking in homes and firing up power stations. As Russia is a major natural-gas supplier to Europe, the natural-gas crunch has sent prices soaring this year, in turn supporting the Kremlin’s coffers. Since it invaded Ukraine on February 24, Russia’s revenue from oil and gas exports to Europe have more than doubled compared to the average in recent years, the International Energy Agency wrote on July 18. While the upcoming winter will be challenging for Europe, it’s the Russian economy that stands to be “hurt the most” in the long run by the shifting natural-gas supply chains, a Yale University analysis found. That’s because “the importance of commodity exports to Russia far exceeds the importance of Russian commodity exports to the rest of the world,” the Yale researchers wrote in the analysis, released July 20. The European Union has agreed to end almost all its oil imports from Russia by the end of this year and has said it will cut coal imports starting in mid-August. European countries including Germany and Italy are also working to wean themselves off Russian gas. To mitigate the impact from lower energy sales to Europe, Russian President Vladimir Putin is hawking Russia’s energy exports to other markets, such as Asia — but at a discount. “It now deals from a position of weakness with the loss of its erstwhile main markets,” the Yale team wrote, adding that Russia’s strategic position as a commodities exporter had “irrevocably deteriorated.”
IndianOil Targets Green Hydrogen Meeting 10% Of Requirements By 2030
To start with, the nation’s largest oil firm is setting up green hydrogen plants at its Panipat and Mathura refineries, IOC said in its latest annual report Indian Oil Corporation (IOC) is targeting to replace at least a tenth of its current fossil-fuel-based hydrogen at its refineries with carbon-free green hydrogen as part of a decarbonization drive. To start with, the nation’s largest oil firm is setting up green hydrogen plants at its Panipat and Mathura refineries, IOC said in its latest annual report. “The company is venturing into green hydrogen production and is targeting 5 per cent of hydrogen produced by it as green hydrogen by 2027-28 and 10 per cent by 2029-30,” it said. Hydrogen is the cleanest known energy source but it barely exists in a pure form on Earth. It either is bounded with oxygen in water or with carbon to form hydrocarbons like fossil fuels. Once separated from other elements, hydrogen’s utility increases: it can be converted into electricity through fuel cells, it can be combusted to produce heat or power without emitting carbon dioxide, used as a chemical feedstock, or as a reducing agent to reduce iron ores to pure iron for steel production. Most of the hydrogen currently produced is grey which is produced from fossil fuel and as carbon emissions. Green hydrogen is produced using electrolysis powered by renewable energy to split water molecules into oxygen and hydrogen, creating an emissions-free fuel. As part of its decarbonisation drive, IOC is looking to replace hydrogen made by unabated fossil fuels with green hydrogen. Petroleum refining accounts for almost 42 per cent of total global hydrogen demand. “At present, the refineries are the major consumption centres for hydrogen, used for desulfurisation. The current dominant hydrogen production process is highly carbon-intensive being based on the Steam Methane Reforming process. “On the other hand, green hydrogen i.e. hydrogen produced from electrolysis of water, using renewable energy, has a zero-carbon profile, making it the preferred form of hydrogen in the context of a carbon neutral future,” IOC said. In the annual report, IOC Chairman Shrikant Madhav Vaidya said to meet the net-zero commitment, the Indian government has announced the Green Hydrogen and Ammonia Policy to boost green hydrogen production to 5 million tonne by 2030 and make India an export hub for this clean fuel. “Aligning with the national priority, Indian Oil will be producing green hydrogen in stages at the Mathura and Panipat refineries. As a first step, we will be implementing a 5 KTA (40 MW) green hydrogen plant at Mathura Refinery and a 2 KTA (16 MW) plant at Panipat Refinery,” he said. To sync with the entire hydrogen value chain, the firm has forged crucial collaborations to develop green hydrogen production assets, associated renewable assets and manufacture electrolysers. “This will be a gamechanger as electrolysers contribute to approximately 30 per cent of the overall cost of green hydrogen,” he said. IOC, he said, is also exploring multiple hydrogen production pathways, including solar electrolysis, biomass gasification and bio-methanation. “The hydrogen produced will be used for fuelling 15 fuel cell buses to establish the efficacy, efficiency and sustainability of the fuel cell technology and hydrogen production processes. In addition, we will commission a hydrogen dispensing station at the Gujarat Refinery to enlarge hydrogen-based mobility coverage,” he said. IOC said it is looking to expand its footprint in the renewable power space from the present level of about 240 MW capacity. While renewable energy plants currently produce electricity equivalent to 5 per cent of its electricity consumption, IOC is targeting nearly 5 GW of renewable electricity generation capacities by 2025 for use at its oil refineries.
Russian Oil Exports Have Stabilized, Revenues Steady
Russia’s oil exports appear to have stabilized, based on Bloomberg data released Monday showing a steady level of 500,000 barrels per day below the peak reached prior to the February invasion of Ukraine. Russian seaborne crude exports reached 3.5 million bpd in the week to July 29th, according to Bloomberg, while the four-week average shows about 3.2 million bdp–a figure that suggests stabilization. More specifically, while Bloomberg reported last week that there were indications Chinese and Indian buyers were slightly letting up on Russian oil purchases, Russia’s crude flows to Asia remain stable post-invasion. In April and May, we saw Russian oil flows to Asia soar to 2.1 million bpd, but July numbers show this leveling off now at 1.75 million bpd. The end result is that Moscow continues to collect sizable oil revenues for its war coffers, with rising crude oil prices upping the ante and filling in gaps for any shortfall in outflows. Bloomberg’s new Russia oil outflow data comes as the G7 attempts to move forward with its plan to place a price cap on Russian oil, with the potential for this to be put in place by December 5th when the European Union’s ban on seaborne crude imports from Russia goes into effect. The oil price cap is designed to reduce Russia’s revenues and thereby reduce the value of its war chest. The price cap scheme would require support from India and China in order to be truly effective. It would also require compliance from Moscow, which is not likely to be forthcoming. Moscow has already said it would not comply and would not sell to any countries agreeing to a price cap, and China, which has refused to condemn Russia’s invasion of Ukraine, is not likely to agree to the West’s plans.
Australia May Limit LNG Exports Amid Domestic Gas Shortage
Australia is again facing a domestic gas shortage because of excessive exports, and the Australian Competition and Consumer Commission is warning that the government must impose limits on LNG exports to secure local supply. This warning follows a decision by the Australian Energy Market Operator to activate a supply guarantee mechanism that was set up in the wake of another looming shortage a few years ago when the Australian government realized it needed a way to ensure that the local market would be well supplied with gas despite rising LNG exports. Per the mechanism, the Australian government has the right to divert LNG cargos from three offshore projects in Eastern Australia from the foreign to the domestic market to ensure it is well supplied. “Australia remains a long-term and reliable supplier of resources and energy, and is a crucial supplier of LNG to our trading partners in north Asia,” resources minister Madeleine King said, as quoted by Argus. “We remain committed to contributing to global energy security and working with international partners to address current global challenges.” According to the Australian Competition and Consumer Commission, if LNG producers are allowed to sell all their uncontracted LNG abroad, the east coast of Australia could suffer a shortfall of about a tenth of the forecast gas demand for 2023, the Australian Financial Review reported. The report noted that demand for natural gas is surging in Australia because of a shift away from coal and not fast enough growth in renewable power generation. “In the current environment of high international energy prices (including gas and LNG), tight LNG markets, broader supply chain problems, geopolitical instability, inflation and uncertain demand for gas powered generation domestically, we support the Australian government placing greater focus on energy security,” the ACCC said in its own report.
UAE’s ADNOC Awards Huge Contracts To Boost Gas Output At Critical Time
The UAE’s state-owned Abu Dhabi National Oil Co. (ADNOC) has awarded $2 billion worth of drilling contracts to spur the development of the Hail and Ghasha sour gas project as part of its plans to help OPEC’s third-biggest producer achieve gas self-sufficiency, and after that to look to exporting the surplus. Becoming self-sufficient in gas part of its broader ‘Operation 300 Billion’ plan that intends to raise the contribution of the country’s industrial sector to AED300 billion (US$81 billion) from the current AED133 billion within the next 10 years. This objective – itself part of the UAE’s Circular Economy Policy 2021-2031 – will be achieved in large part through the creation of 13,500 industrial companies over that period, covering the manufacturing, construction, electricity, gas, mining and quarrying sectors in the first instance. Self-sufficiency in gas will also allow the UAE to build out a strategic petrochemicals sector and to avoid being reliant on Qatar for the gas that it requires for its electricity grid. In keeping with this idea of self-sufficiency, ADNOC awarded the US$2 billion of contracts to its affiliate, ADNOC Drilling, in which it has a stake. A significant part of the work will be focused on the development of the Ghasha concession, the world’s largest offshore sour gas development, production from which is expected to begin in 2025, with the target being the production of at least 1.5 billion cubic feet per day (bcf/d) of gas by 2030. This vast concession comprises not just the Ghasha field itself but also the Hail, Hair Dalma, Satah, Bu Haseer, Nasr, SARB, Shuwaihat, and Mubarraz fields as well. ADNOC’s partners in the overall concession are Italy’s Eni (25 percent stake), Germany’s Wintershall Dea (10 percent), Austria’s OMV (5 percent), and Russia’s Lukoil (5 percent). “ADNOC is committed to unlocking the UAE’s abundant natural gas reserves to enable domestic gas self-sufficiency, industrial growth and diversification, as well as to meet growing global gas demand,” said ADNOC’s chief executive officer, Sultan al-Jaber, in Abu Dhabi last week. This drive towards self-sufficiency in the gas sector was energised after the huge shallow gas field discovery made in 2020 in Jebel Ali, which, according to statements from the companies developing the site – ADNOC, and the Dubai Supply Authority – holds around 80 trillion cubic feet of gas across a 5,000 square kilometre area between Abu Dhabi and Dubai. Following this, the hunt for further sizeable gas deposits picked up pace, and not just in the vicinity of the previous discoveries. Another of the UAE’s constituent emirates, Sharjah, also recently announced proposals to launch an offshore bidding round for its new gas and condensate find. The bidding, which is officially mooted to start in early 2023 but which may occur later this year, according to legal sources in Abu Dhabi spoken to by OilPrice.com last week, relates to Sharjah’s Block B, run jointly by Eni and the state-owned Sharjah National Oil Corp (SNOC). Late in 2020, the two companies discovered the Mahani reservoir, and subsequent first drilling yielded up to 1.4 million cubic metres per day (mcm/d) of lean gas and associated condensate. First gas was also produced this year from the Mahani-1 gas well, but no volume data was released by the companies, although SNOC did state that it is continuing to limit production from Mahani-1 at less than 1.4 mcm/d to collect data and map out the full potential of the reservoir. Further drilling by the two companies, which also work together in onshore concession areas A and C, is set to continue with two new wells, according to the statement by SNOC, and the company added recently that the initial seismic data on the developments show ‘significant’ reserves that will be ‘very economical’ to produce and develop. Just prior to last week’s contract awards for gas development, ADNOC signed a partnership agreement with France’s TotalEnergies that includes cooperation in trading, product supply and carbon capture, utilisation and storage. This in line with, on the one hand, the UAE’s target of increasing its crude oil production to 5 million barrels per day (bpd), from around 4 million bpd currently, again by 2030, and, on the other hand with France’s policy of attempting to reduce its own dependence on Russian energy imports. As highlighted and analysed by OilPrice.com recently, TotalEnergies is at the vanguard of this policy, certainly in the Middle East, and the company stated about the partnership deal that: “[The agreement includes] the development of oil and gas projects in the UAE to ensure sustainable energy supply to the markets and contribute to global energy security.” This comment came after the signing of the UAE-France Comprehensive Strategic Energy Partnership, which also focuses on securing energy supply for France going forward. Such concerns about the negative effects for France resulting from the staggered bans on Russian energy ahead were echoed again earlier in July by France’s economy minister, Bruno Le Maire, who said: “Let’s prepare for a total cut-off of Russian gas; today that is the most likely option.” Although France receives slightly less than 20 percent of its gas imports from Russia – much less than several other European Union (EU) states – its liquefied natural gas (LNG) imports fell by nearly 60 percent month-on-month (m-o-m) in June, to around 1.06 million metric tonnes, according to industry data. In addition to the new elements delineated in the partnership agreement, TotalEnergies has, in the gas sector alone: a 40 percent stake in the Ruwais Diyab unconventional gas concession, the output target of which is 1 bcf/d by 2030, and which saw first production in 2020; a 15 percent stake in ADNOC Gas Processing, which produces natural gas liquids and condensate from the associated gas produced by ADNOC Onshore; and a 5 percent stake in ADNOC LNG (liquefied natural gas). In the oil sector, TotalEnergies also has an abundance of interests in UAE projects, including: a 20 percent stake in the Umm Shaif/Nasr oil field; a 5 percent stake in Lower Zakum;
Rosneft starts production drilling at Payakhskoye field of Vostok Oil project
Rosneft has started production drilling at the Payakhskoye field on the Taimyr Peninsula. The Russian energy company plans to drill about 80 wells there by the end of this year. The Payakhskoye field is part of Rosneft’s Vostok Oil strategic project. Its license fund consists of 52 subsoil plots, within which 13 fields have been discovered, four of which have already been put into development using the latest technologies. The project’s resource base of 6.2 billion tonnes of oil has been confirmed by extensive exploration work, detailed reports by world-class experts and international auditors. These resources are comparable to the largest oil provinces in the Middle East or the US shale formations and are also commensurate with another legendary Russian field, the Samotlor field in the Khanty-Mansi Autonomous Region (7.1 billion tonnes). The development of the Samotlor field allowed the Soviet Union to become one of the leaders in the international hydrocarbon market. But the era of this West Siberian oil province is coming to an end, while the era of the Taimyr is just beginning. According to Rosneft’s plan, production at the project will reach 115 million tonnes by 2033. With the decline in investment in oil and gas that the world has seen over the past few years, Vostok Oil is the only project capable of having a stabilising effect on hydrocarbon markets. Over the past five years alone, total upstream capital expenditure by the largest energy companies has fallen by 29 per cent, and total investment in the oil and gas industry has fallen by 26 per cent over the past decade. At the same time, according to JP Morgan, global energy demand is set to outpace supply by 20 per cent as emerging economies grow rapidly and work to improve living standards and quality of life. To eliminate the deficit in oil alone by 2030, the world needs an additional investment of $400 billion. Against the backdrop of reduced investment, analysts predict that this level is unlikely to be achieved, and the oil deficit may persist for a long time. The fact that Rosneft is launching a major energy project amid increasing external economic pressure shows the enormous sustainability of both the project and the company as a whole. The unique, sustainable economic model of Vostok Oil is an essential factor contributing to the project’s investment attractiveness. Rosneft has already received opinions from leading international experts confirming the project’s resource base, development technologies, and economics. Major international investment banks highly value Vostok Oil: JPMorgan (NYSE:JPM) – $114 billion, Raiffeisen – $90 billion, Citi – $86 billion, Goldman Sachs (NYSE:GS) – $85 billion, Bank of America (NYSE:BAC) – $70 billion. The perimeter of the project includes a whole complex of oil transport, airport and energy infrastructure, including the country’s largest oil transhipment terminal on the Northern Sea Route with a capacity of 100 million tonnes per year, 7,000 km of pipelines, 3.5 GW of new capacity, helipads, etc. Rosneft has already started the construction of the unique port Bukhta Sever in the Yenisei Bay in the west of the Taimyr Peninsula. The port infrastructure includes three cargo and two oil loading berths with a total length of almost 1.3 km, Russia’s largest receiving and loading station with 27 reservoirs of 30,000 cubic meters each, and technological and auxiliary infrastructure facilities. The oil loading terminal in the Bukhta Sever is a strategically important facility, providing oil transhipment from the fields of Vostok Oil via the Northern Sea Route. It will become Russia’s largest oil loading terminal with an oil receiving and storage fleet. By 2030, it will have 102 tanks. Supplying raw materials from the fields to all international markets, especially the Asia-Pacific region, is a logistical advantage of the Vostok Oil project. Oil will be supplied to the Bukhta Sever port via the pipeline system under construction from the fields of the Payakh and Vankor clusters. The total length of the trunk oil pipelines will be about 770 km. Using the infrastructure of the first phase, the volume of oil transhipment through the sea terminal of the port Bukhta Sever can reach 30 million tonnes per year, with subsequent gradual reaching a total transhipment volume of 100 million tonnes in 2030. Own pipelines and port will allow to maintain the marketable characteristics of oil produced under Vostok Oil. This oil is characterised by unique premium qualities with extremely low sulfur content from 0.01 to 0.04 per cent and low density. For comparison, Brent has 0.45 per cent, WTI 0.45 per cent, Urals 1.5 per cent, ESPO 0.5 per cent, Siberian Light 0.6 per cent, and Eagle Ford (Texas) has 0.2 per cent. Vostok Oil’s low unit production costs and minimal carbon footprint, which is 75% lower than other major projects, make it today the most environmentally friendly, “green” hydrocarbon production project. “The project includes wind power to maximise the transition to clean energy consumption with zero greenhouse gas emissions,” Vostok Oil General Director Vladimir Chernov said. “It is too early to talk about the planned capacity of wind power plants (WPPs). The final decision will be made after a study of the wind energy potential of the territory. But it is already clear that the maximum capacity of wind power plants can reach 200 MW. China’s leading wind energy companies are considered potential partners,” Chernov said. In November 2021, Rosneft reported that it had signed cooperation agreements with several Chinese companies to study the wind energy potential of the project. Vladimir Chernov said the project would also provide 9 to 12 gas turbine power plants with 300 MW to 1 GW capacity. “We are considering building a power system where the power plants will be staged with associated petroleum gas nearby,” he specified. The company reported that Vostok Oil would use 99 per cent of its associated petroleum gas to power its power stations, one of Russia’s highest associated petroleum gas utilisation rates. The project fields now consume about 400 MW of electricity. The Vankor power
ONGC in aggressive oil & gas discovery drive; to bring in global partners
India’s largest public sector enterprise (PSE) Oil and Natural Gas Corporation (ONGC) is embarking on an aggressive oil and gas exploration and production (E&P) plan as its producing fields are ageing and production is coming down. The energy major is planning to team up with global experts for joint E&P efforts and is close to signing a memorandum of understanding (MoU) with U.S. energy giant ExxonMobil, Alka Mittal, chairman and managing director of ONGC told Fortune India. In an exclusive interaction, Mittal says ONGC is planning to invest ₹31,000 crore in the next three years in exploration. This will help the company achieve its acreage acquisition programme to bring around 5,00,000 sq. km. under active exploration by 2025. ONGC has initiated the process of acquiring 70,000 line kilometre (LKM) 2D seismic data in eastern and western offshore areas under government funding. To bring the Andaman Basin under accelerated exploration, activities on the ‘National Island Exploration Project’ has also been initiated by the company. Over the past five years, ONGC has made cumulative core E&P spends of over ₹1500 billion. To date, 20 major projects are under implementation, with a total project cost of around ₹590 billion, with an envisaged gain of 85.5 million metric tonnes of oil equivalent (mmtoe), she says. ONGC is expecting its crude oil production to rise from 19.545 million tonnes in FY22 to 19.88 million tonnes this year. The output is expected to rise to 21.701 million tonnes by 2024-25. Gas production is expected to rise from 20.907 billion cubic meters (bcm) in FY 22 to 21.097 bcm in FY23 and to 26.124 bcm by FY26. A big challenge ONGC is facing is the portfolio of ageing fields. The majority of its fields are decades old and intervention in terms of technology upgradation and implementation of innovative solutions to augment oil and gas production is the need of the hour, says the ONGC CMD. “We have been reaching out to global majors for collaborative efforts in exploration and production activities. Towards developing our small and marginal fields, we are seeking partnerships with domestic companies. This will also help build an ecosystem with ONGC facilitating new players to come up and prosper in the Indian E&P system,” she says. She notes there was a period when crude oil prices were very low, and globally, during low crude oil price windows, the investment in upstream business came down. “However, being the national oil company of India, ONGC was one of the few E&P companies in the world, which did not cut their CAPEX, so as to ensure the much-needed energy for the country does not drop down due to low investments”, says Mittal. While legacy fields continue to be the mainstay of base production, there is significant traction on the development of new fields as well as new schemes for maximising recovery in mature areas. Further, ONGC is strongly pursuing projects for improving recovery from existing fields, she says. ONGC made four oil and gas discoveries during the last year. The biggest exploratory success last year was at Hatta#3 in Son valley of Madhya Pradesh, where the well produced more than 60,000 cubic meters per day on testing and confirmed the commercial production potential of Vindhyan Basin. With development and production, this has the potential of becoming the ninth producing basin of India. Similarly, a mega offshore deep-water project on the East Coast, Cluster-2 Development of KG-DWN-98/2, is expected to substantially enhance our natural gas production, says Mittal.
GAIL rationing gas as former Gazporm unit cuts supplies
India’s largest gas distributor GAIL (India) Ltd has started gas rationing, cutting supplies to fertiliser and industrial clients after imports were hit under its deal with a former unit of Russian energy giant Gazprom, two sources familiar with the matter said. Lower gas supplies will affect impact India’s urea production, and a sustained cut would lift imports of the soil nutrient, a fertiliser industry source aware of the cuts said. Neither GAIL nor India’s fertiliser ministry responded to Reuters’ requests for comments. Gazprom Marketing and Trading Singapore (GMTS), now a subsidiary of Gazprom Germania, has failed to deliver some liquefied natural gas (LNG) cargoes to GAIL and has said it may not be able to meet supplies under their long-term deal. GAIL, which imports and distributes gas and also operates India’s largest gas pipeline network, has cut supplies to some fertiliser plants by 10% and restricted gas sales to industrial clients to the lower tolerance limit of 10%-20%, the sources said. The state-run company is operating its petrochemical complex at Pata in northern India at about 60% capacity to save gas for other clients, they said. GAIL has advanced maintenance shutdown of some units at the 810,000 tonne-a-year plant, one of the sources added. An industrial consumer said GAIL has restricted its gas quantities to a ‘take or pay level’, the lowest level at which it will not attract a penalty from the customer. GAIL’s measures will cut gas supplies to clients by about 6.5 million cubic meters a day, while imports under the Gazprom deal were averaging about 8.5 mcmd, a separate source said. “We don’t know where else we can cut supplies… Indian customers cannot afford costly spot gas,” the second source said. This source said that GAIL has written repeatedly to Gazprom Germania about supplies under the deal. Last month, GAIL bought a spot LNG cargo at $38 per million British thermal units (mmBtu) for August loading, well above the level at which it was getting gas under its deal with Gazprom, at about $12-$14 per mmBtu. GAIL agreed a 20-year deal with Russia’s Gazprom in 2012 for annual purchases of an average 2.5 million tonnes of LNG. Supplies under the contract began in 2018. GMTS had signed the deal on behalf of Gazprom. At the time, Gazprom Germania was a unit of the Russian state firm. However, following Western sanctions against Russia over its invasion of Ukraine, Gazprom gave up ownership of Gazprom Germania in early April without explanation and placed parts of it under Russian sanctions.
Demand Destruction Could Help America Refill Its Oil Inventories
U.S. petroleum inventories are still sitting at multi-year lows for this time of the year despite record releases from the Strategic Petroleum Reserve (SPR), reports of weakening gasoline demand over the past weeks because of high prices, and a slowing economy. Commercial crude and product stockpiles have failed to rebuild over the last few months, and the low levels point to continued tight markets for gasoline and diesel in the short term, potentially supportive of oil prices. Yet, emphasis has been placed on a fall in U.S. gasoline demand in recent weeks after the national average price hit a record $5 a gallon in the middle of June. This, combined with fears of a recession, have weighed on WTI Crude prices. The U.S. benchmark hit this week its widest discount in over three years compared to the international Brent Crude benchmark. This faltering demand for gasoline has weighed on WTI, while Brent prices reflect tight global physical supplies, buoyed by Russia’s war on Ukraine and Western sanctions, as well as the European Union ban on Russian oil set to be implemented before the end of this year. The biggest discount of WTI to Brent in three years is driving a surge in U.S. crude oil exports, which hit a record high of 4.5 million barrels per day (bpd) in the reporting week to July 22. The most recent data, however, shows that gasoline demand destruction isn’t as clear-cut as it initially looked, with the four-week average gasoline demand still trending upward, according to EIA data. Despite signs of downward price pressures on WTI Crude, the lowest U.S. petroleum inventories in years—for some products in decades—are one strong bullish factor for oil prices, although it’s not a given that it could outweigh market fears of recession. In the latest reporting week to July 22, commercial crude oil inventories declined by 4.5 million barrels, the EIA data showed. At 422.1 million barrels, U.S. crude oil inventories are about 6% below the average for this time of the year. In gasoline, inventories decreased by 3.3 million barrels last week and are about 4% below the five-year average for this time of the year. Distillates, which include diesel, have been the tightest market this year, with current stockpile levels 23% below the seasonal five-year average. Distillate fuel oil inventories, which are most closely related to the economic cycle, are at the lowest for the time of year since 2000, according to data compiled by Reuters market analyst John Kemp. So far in the third quarter, distillate stockpiles have risen by less than 1 million barrels, an unusually low pace of inventory builds. This is one of the tiniest distillate inventory builds of the past four decades, Kemp notes. An economic slowdown could help rebalance those very low levels of distillate stocks, but the rebalance could need a deeper and longer downturn in activity, Kemp argues. Indeed, the U.S. economy is slowing down. The advance estimate from the U.S. Department of Commerce showed on Thursday that GDP contracted by 0.9% in the second quarter, following a 1.6% decline in Q1. In theory, the GDP data met one common definition of a recession—two consecutive quarters of GDP contraction. But policymakers insist the ‘technical’ recession is not a broad-based recession because many areas in the economy are still going strong, especially the labor market, and external conditions pushing inflation higher are unique. “When you’re creating almost 400,000 jobs a month, that is not a recession,” U.S. Treasury Secretary Janet Yellen said on NBC’s Meet the Press last weekend, a few days before the GDP data was released. Policymakers admit there is a slowdown, but the U.S. economy doesn’t present broad-based signs of a recession. “I do not think the U.S. is currently in a recession. And the reason is there are just too many areas of the economy that are performing too well,” Fed Chair Jerome Powell said at a press conference this week after the Fed announced another 75-basis-point hike in key interest rates. “Really the growth was extraordinarily high last year, 5 and a half percent. We would have expected growth to slow. There’s also more slowing going on now,” Powell said, reiterating the Fed’s goal of a “soft landing.” “If you think about what a recession really is, it’s a broad-based decline across many industries that sustain for more than a couple of months and there are a bunch of specific tests in it. And this just doesn’t seem like that,” the Fed Chair added.