China Is Quietly Building A Green Energy Empire In Latin America
China is rapidly expanding its green energy production and growth potential and, in doing so, is quickly gaining influence in key emerging markets around the world. While China is busily making inroads in renewable energy markets in Southeast Asia, Africa, and even the West, nowhere has its sphere of influence grown more rapidly or completely than in Latin America. China has been vastly outpacing the rest of the world in terms of clean energy spending, with more numerous and more developed clean energy supply chains than anywhere else on the planet. China alone was responsible for nearly half of all renewable energy spending worldwide in 2022, totalling a whopping $546 billion USD according to figures from a BloombergNEF analysis released early this year. This figure crushed the next-biggest spenders, the US and the EU: Beijing’s spending nearly quadrupled Washington’s $141 billion in clean energy spending, and was 2.5 times more than the EU’s $180 billion. China’s intensive spending on the sector has paid off; the country’s clean energy sectors are now economically independent enough to be weaned off of heavy government support, and are now outcompeting every other clean energy leader on the global stage. “China has managed to nurture these really integrated, efficient value chains for making things like solar panels, for making things like battery cells,” Antoine Vagneur-Jones, head of trade and supply chains research at BloombergNEF, was recently quoted by Scientific American. Due to the massive head start that China has in these sectors – not to mention its near-complete control over many rare Earth metals markets – it’s more than likely that Beijing will continue to dominate for at least the next decade, if not longer. This dynamic is especially pronounced in Latin America, where around 90% of all installed wind and solar technologies are produced by Chinese companies. As of 2023, Beijing has active free trade agreements with Chile, Costa Rica, Ecuador, and Peru (and is currently in negotiations with Uruguay), and so far 21 Latin American countries have signed on to China’s massive international infrastructure investing scheme, the Belt and Road Initiative (BRI). China’s State Grid now controls the majority of Chile’s regulated energy distribution. Similar problems are unfolding in Peru. Earlier this year, a Peruvian industry group warned that a major deal in development for a Chinese company to buy out two local power suppliers “would hand the Asian country a near monopoly over the sector in Peru, particularly in and around populous capital Lima.” The deal, which is still awaiting regulatory approval, would just be the latest of a long series of Chinese acquisitions in Peru. “If approved, it would lead to a concentration of 100% of Lima’s electricity distribution market in the hands of the People’s Republic of China,” the Peruvian National Society of Industries, a chamber of private companies, was quoted by Reuters. Beijing is also rapidly ramping up its investments in Latin American minerals. The continent is rich in key materials in renewable energy and electric vehicle manufacturing such as lithium, nickel, and cobalt. China is already the “dominant producer of rare earths and graphite globally,” The South China Morning Post recently reported based on recent BloombergNEF data. “It also owns around a third of global rare earths, a sixth of graphite and an eighth of lithium reserves.” And expanding its acquisitions of Latin American minerals is a key part of China’s strategy. Chinese companies already own major stakes in one of the largest lithium producers in Chile, has purchased a ‘major evaporative lithium project’ in Argentina, and has signed dozens of trade-strengthening agreements with Brazil. And China is not the only global power eyeing Latin American lithium. The United States, too, has a vested interest in forging trade agreements with the continent’s producers of rare Earth minerals. In fact, it’s a key part of the nation’s strategy to catch up with China and become competitive in renewable energy markets. However, countries in Latin America are increasingly talking about shying away from such agreements with the US and China in the interest of shoring up their own manufacturing industries and taking advantage of value-addition opportunities domestically.
Indian Importers Of Russian Oil Brace For Banking Problems
Indian refiners buying Russian crude are preparing for problems with their bankers as the flagship Russian oil grade topped the G7-imposed price caps. In a report citing sources from three Indian refiners, Bloomberg wrote today that the companies were bracing up for more requirements from banks before they grant them the loans to buy the cargoes. Russia’s flagship crude grade, which has been trading consistently below the price cap set by the G7 and the European Union, climbed above $60 per barrel on Wednesday and remained there. It is now, for the first time, that observers can judge if the price cap is actually working. Before, with Urals trading below it anyway, it could hardly be argued that the cap was doing anything to deliberately squeeze Russia’s oil export income. Earlier this week, energy analyst Vandana Hari from Vanda Insights noted that this price for Urals will be problematic for Indian buyers. “Indian banks have been extra cautious in the last few months for fear of sanctions, requiring the refiners to show that the free-on-board price of their cargo was below $60 in order to put the payment through,” Hari told Bloomberg. According to the more recent Bloomberg report, buyers expect their bankers to start asking for more evidence to verify the price, at which the crude is being bought. Also, importers of Russian crude will stop using Western insurance and tanker services – the basis on which the price cap was designed. As long as the price of the crude was below $60 per barrel, buyers could use Western shipping transport and insurance. If the price moved above $60 access to insurers and tanker owners in the West shut off. According to one of the sources that Bloomberg spoke to, a switch from dollars to other currencies for payments for Russian cargo was also an option under consideration.
Lower prices help RIL-BP, Nayara treble share in June diesel sales
Reliance-BP and Nayara Energy have nearly tripled their share of the country’s diesel sales to 9.4% in June from a year earlier, using price discounts to regain domestic customers they had lost last year while focusing on the high-margin export market. RIL-BP’s share in total diesel sales rose to 4% in June from 1.2% in the same month a year earlier. Rosneft-backed Nayara Energy’s share has expanded to 5.4% from 2%. Shell’s share remained stagnant at 0.1%. As a result, the share of state-run players has dropped to 90.5% from 96.7% despite BPCL and HPCLgaining marginally. Indian Oil Corp has been the only loser in the game, with its share declining to 41.4% from 49.1%. Indian Oil’s market share gain was equally dramatic last year, rising from 42.4% in June 2021 as it stepped in to fill the gap left by the private players.
India not looking to cut excise duty on fuel right now: Revenue Secretary Sanjay Malhotra
India is currently not looking at lowering the excise duty on petroleum and diesel with rates already quite low following the two cuts administered in November 2021 and May 2022, Revenue Secretary Sanjay Malhotra told Moneycontrol in an interview. “The government continuously monitors inflation and takes measures on excise as well as customs side to control it on need basis. This is ongoing exercise not only for petrol and diesel but also for many other essential produces,” Malhotra added. In November, 2021, the central government reduced the excise duty on per litre of petroleum by 5 rupees and on diesel by 10 rupees, while another round of cuts came in May, 2022, wherein the duty was lowered by 8 rupees on a litre of petrol and 6 rupees on diesel. The central government’s collections from excise duties have been pegged at 3390 billion rupees for the current fiscal, targeting a growth of nearly 6% over the revised estimates of the previous financial year. Infact, for FY23, the government has revised downwards the Budget estimate for mop up from excise duties by 150 billion rupees.
U.S. Shale Challenges OPEC With Record Production In 2023
Last year, oil prices hit multi-decade highs shortly after Russia invaded Ukraine, prompting the Biden administration to urge U.S. producers and OPEC to ramp up production at a faster clip so as to rein in spiraling oil prices. However, Saudi Arabia and its allies responded by doing the exact opposite, cutting production when oil prices started plummeting. Predictably, the United States and Europe were irked by the cartel’s defiance, with President Joe Biden’s administration accusing Saudi Arabia of colluding with Russia and supporting its war in Ukraine. Well, President Biden can at least thank his lucky stars that the U.S. Shale Patch paid heed to his clarion call: the Energy Information Administration (EIA) has forecast total U.S. output will hit 12.61M bbl/day in the current year, eclipsing the previous record of 12.32M bbl/day set in 2019’s and easily beating last year’s 11.89M bbl/day. U.S. crude oil output is up 9% Y/Y blunting OPEC’s efforts to keep supplies low in a bid to goose prices. There is little doubt the U.S. Shale Patch is largely responsible for keeping oil markets well supplied and oil prices low: Rystad Energy has estimated that whereas OPEC and its allies have announced cuts amounting to ~6% of 2022’s production, non-OPEC supply has made up for two-thirds of those cuts, with the U.S. accounting for half of that. Energy experts have generally been bearish about U.S. crude supply with many arguing it has already peaked, “The projection suggests the pace of US shale growth, one of the few sources of major new supply in recent year, is slowing despite oil prices hovering at around $90 a barrel, about double most domestic producers’ breakeven costs. If the trend continues, it would deprive the global market of additional barrels to help make up for OPEC+ production cuts and disruption to Russian supplies amid its invasion of Ukraine,” Bloomberg said, Bloomberg cited comments by ConocoPhillips (NYSE: COP) CEO Ryan Lance that rising costs as well as limited supplies of labor and equipment were some of the problems that were hamstringing efforts by U.S. shale producers to quickly ramp up production. However, Bloomberg also noted that the biggest factor behind the slowdown is a change of the playbook by the majority of U.S. shale companies from focussing on growth and expansion to more capital discipline and returning more cash to shareholders. Improved Efficiency Luckily for the Shale Patch, improving drilling and cost efficiency not only means they are able to squeeze more for less but they are also able to eke out a profit at much lower oil prices. According to J.P. Morgan, U.S. drilling and fracking costs have declined 36% since 2014, significantly lowering the breakeven points of many producers. For instance JPM points out that increased efficiency means EOG Resources (NYSE:EOG), for example, can earn as much from oil priced at $42/bbl today as it would have from $86/bbl oil in 2014; in contrast, Saudi Arabia reportedly requires ~$81/bbl oil to balance its books. The U.S. shale revolution dramatically reshaped the world energy markets. The shale boom was one of the most impressive growth stories, from take off in 2008 to the Permian stealing the mantle from Saudi Arabia’s Ghawar as the world’s highest producing oilfield in a little over a decade. Overall, Reuters has estimated that, “U.S. petroleum production is at least 10-11 million bpd higher than it would have been without horizontal drilling and hydraulic fracturing.’’ Unfortunately, the Shale Patch has lately been struggling to ramp up production due to a litany of challenges including pressure from investors to boost returns, limited equipment and workers as well as a lack of capital. But shale giant ExxonMobil Corp. (NYSE:XOM) is now betting that shale producers can double crude output from their existing wells by employing novel fracking technologies. “There’s just a lot of oil being left in the ground. Fracking’s been around for a really long time, but the science of fracking is not well understood,” Exxon Chief Executive Officer Darren Woods said Thursday at the Bernstein Strategic Decisions conference. Woods has revealed that Exxon is currently working on two specific areas to improve fracking. First off, the company is trying to frack more precisely along the well so that more oil-soaked rock gets drained. It’s also looking for ways to keep the fracked cracks open longer so as to boost the flow of oil. Shale Refracs Luckily, the U.S. Shale Patch won’t have to wait for Exxon to perfect its new fracking technologies. There’s already a proven technology for oil producers to return to existing wells and give them a second, high-pressure blast to increase output for a fraction of the cost of finishing a new well: shale well refracturing. Refracturing is an operation designed to restimulate a well after an initial period of production, and can restore well productivity to near original or even higher rates of production as well as extend the productive life of a well. Re-fracking can be something of a booster shot for producers–a quick increase in output for a fraction of the cost of developing a new well. While refracturing has never really gone mainstream, the technique is seeing higher adoption as drilling technology improves, aging oilfields erode output, and companies try to do more with less. According to a report published in the Journal of Petroleum Technology, new research from the Eagle Ford Shale in south Texas shows that refractured wells using liners are even capable of outperforming new wells despite the latter benefiting from more modern completion designs. JPT also estimates that North Dakota’s Bakken Shale straddles some 400 openhole wells capable of generating an excess of $2 billion if refractured. Mind you, that estimate is derived from oil prices at $60/bbl vs. this year’s average oil price of almost $90/bbl. According to Garrett Fowler, chief operating officer for ResFrac, a refrac can be up to 40% cheaper than a new well and double or triple oil flows from aging wells. How Refracs Work Fowler says the
Russia’s Urals Oil Breaches $60 Price Cap For The First Time
Russia’s flagship crude grade, which has been trading consistently below the price cap set by the G7 and the European Union, climbed above $60 per barrel on Wednesday. That’s supported by Argus Media data, cited by Bloomberg. It is now, for the first time, that observers can judge if the price cap is actually working. Before, with Urals trading below it anyway, it could hardly be argued that the cap was doing anything to deliberately squeeze Russia’s oil export income. In fact, because another Russian grade, ESPO, has been consistently trading above the price cap, it could be argued that the cap was not the most effective of tools, mostly creating a headache for Western insurers and shipowners. But now that Urals has jumped above the cap, even temporarily, things could get interesting—and unpleasant for buyers. According to energy analyst Vandana Hari from Vanda Insights, when it comes to India “It’s problematic.” “Indian banks have been extra cautious in the last few months for fear of sanctions, requiring the refiners to show that the free-on-board price of their cargo was below $60 in order to put the payment through,” Hari told Bloomberg. If Urals jumps above $60 again, it means Russia and its oil buyers would have to increase the use of non-Western insurers and tanker operators to avoid punitive action from the G7 and the EU. “We are monitoring the market closely for potential violations of the price cap,” the U.S. Treasury said in a statement cited by Bloomberg. “It is worth noting that trades above $60 that do not use Coalition services are not in violation of the price cap and a substantial proportion of Russian oil trades, though, still use Coalition service providers.”
Petroleum Ministry lowers domestic content criteria, purchase preference advantage for homegrown firms in oil & gas PSUs LSTK, EPC projects
Prime Minister Narendra Modi’s push for Make in India suffered a setback on Tuesday with Petroleum Ministry lowering the domestic content criteria as well as purchase preference advantage for homegrown firms in lumpsum turnkey (LSTK) or engineering, procurement and construction (EPC) projects floated by oil and gas public sector undertakings (PSUs To give preference to local suppliers and to promote domestic manufacturing and production of goods and services, India in 2017 classified a Class-I local supplier, with local content ‘equal to or more than 50 per cent’, as the winner in all PSU global contracts provided the Class-I supplier sourced 50 per cent of its content locally and matched the lowest bid, even if it had quoted 20 per cent higher than the lowest bid. These thresholds were greatly reduced on Tuesday through a Ministry order whereby the domestic content contribution was lowered to 30 per cent — gradually escalating to 50 per cent — and the purchase preference price differential reduced to 10 per cent across the board and for all years to come. That, in essence, means that any foreign firm stands a chance to win LSTK and EPC contracts even if it domestically sources 30 per cent of the project value (instead earlier 50 per cent) and majorly, that domestic Class-I firms would have to be well within 10 per cent price range (instead of the earlier 20 per cent) quoted by a foreign firm to bag the purchase preference advantage. “…to increase competition and to incentivize progressive increase in Minimum Local Content (MLC) in high value oil and gas LSTK/EPC contracts/projects, it has been decided under para 14 of the Public Procurement (Preference to Make in India) Order 2017 to revise the MLC for getting the purchase preference and Margin of PP for such contracts/projects on progressive basis with predictable trajectory,” says the Ministry’s July 11 order.
Demand for term LNG contracts firms amid supply security concerns
LNG term contract volumes have leapt this year, as energy security becomes paramount worldwide, with markets — most notably among them China — snapping up deals to head off potential shortages, industry sources and analysts have told S&P Global Commodity Insights. While long-term deals have become increasingly appealing to buyers, short and medium-term arrangements have remained important, due to the flexibility they provide, industry observers said. The LNG supply response takes a minimum of around four years to come through and 2022-27 represents a period of “reshuffle”, according to Michael Stoppard, global gas strategy lead and special adviser with S&P Global Commodity Insights. Most of the recent term deals have been for volumes from either projects yet to reach final investment decision, or from part of capacity expansions at existing developments.
Iraq Takes First Step Towards Becoming The World’s Biggest Oil Producer
Iraq’s parliamentary oil and gas committee plans to increase the country’s oil production to more than five million barrels per day, according to the release of committee minutes last week. As analysed in full in my new book on the new global oil market order, not only could this be done with relative ease by Iraq but it could also easily be the precursor to further oil production increases to 13 million barrels per day (bpd) if handled correctly. This would make Iraq the biggest oil producer in the world. In broad terms, Iraq remains the greatest relatively underdeveloped oil frontier in the world. Officially, according to the EIA, it holds a very conservatively-estimated 145 billion barrels of proved crude oil reserves (nearly 18 percent of the Middle East’s total, and the fifth biggest on the planet). Unofficially, it is extremely likely that it holds much more oil than this. In October 2010, Iraq’s Oil Ministry increased its own figure for the country’s proven reserves to 143 billion barrels. However, at the same time as producing the official reserves figures, the Oil Ministry stated that Iraq’s undiscovered resources amounted to around 215 billion barrels. This was also a figure that had been arrived at in a 1997 detailed study by respected oil and gas firm, Petrolog. Even this figure, though, did not include the parts of northern Iraq in the semi-autonomous region of Kurdistan. This meant, as highlighted by the IEA, that most of them had been drilled during a period before the 1970s began when technical limits and low oil prices gave a narrower definition of what constituted a commercially successful well than would be the case now. Overall, the IEA underlined that the level of ultimately recoverable resources across all of Iraq (including the Kurdistan region) at around 246 billion barrels (crude and natural gas liquids). Given the true scale of Iraq’s oil reserves – and the fact that the average lifting cost per barrel of oil in the country is US$1-2 pb (the lowest in the world, along with Iran and Saudi Arabia) – what sort of oil output could reasonably be expected? Back in 2013, the Integrated National Energy Strategy (INES) was produced, and this analysed in detail three realistic forward oil production profiles for Iraq and what each would involve. As also analysed in my new book, 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 for a long-sustained 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). Consequently, the 5 million bpd figure announced last week can be regarded as the first easily achievable stepping stone toward those figures. Indeed, according to Iraq’s Oil Minister, Hayan Abdel-Ghani, last week, the country’s oil production capacity already stands above this level – at 5.4 million bpd – although it is still only producing around 4.3-4.5 million bpd overall. The question at this point is, with these enormous reserves in place, and specific plans on how to turn these into up to 13 million bpd in the Oil Ministry’s files, why is Iraq not already producing a lot more oil than it is? The reason is the ongoing endemic corruption that lies at the heart of Iraq’s oil and gas industry. This not only removes enormous amounts of money from Iraq’s coffers that could fund much-needed infrastructure investments but also deters Western companies with the required technology, logistical expertise, and personnel from becoming too involved in the country. Although commissions are standard practice in the Middle East – and indeed across many business around the world – the practice has become something else entirely in Iraq. This has been highlighted repeatedly by OilPrice.com and independently over many years by Transparency International (TI) in various of its ‘Corruption Perceptions Index’ publications, in which Iraq normally features in the worst 10 out of 180 countries for its scale and scope of corruption. “Massive embezzlement, procurement scams, money laundering, oil smuggling and widespread bureaucratic bribery that have led the country to the bottom of international corruption rankings, fuelled political violence and hampered effective state building and service delivery,” TI states. “Political interference in anti-corruption bodies and politicisation of corruption issues, weak civil society, insecurity, lack of resources and incomplete legal provisions severely limit the government’s capacity to efficiently curb soaring corruption,” it concludes. The sums of money that Iraq has lost could have funded all the major projects needed to boost oil production up to at least 7 or 8 million bpd to begin with, notably the crucial Common Seawater Supply Project (CSSP), as also analysed in my new book. According to a statement made in 2015 by then-Oil Minister – and later Prime Minister of Iraq – Adil Abdul Mahdi, Iraq “lost US$14,448,146,000” from the beginning of 2011 up to the end of 2014 as “cash compensation” payments to international oil companies and to other entities. In basic terms, the way in which such a staggering sum was lost relates to the way in which gross remuneration fees, income tax and the share of the State partner was deducted and accounted for in the compensation paid out over reduced oil production levels. The sheer scale and scope of this corruption created the unwillingness of major Western firms to become too heavily involved in the country. In June 2021, U.K. oil super-major, BP, said it was working on a plan to spin off its operations in Iraq’s supergiant Rumaila oil field into a standalone company. The statement was highly reminiscent of the withdrawal of the U.K.-Dutch oil super-major, Shell, from Iraq’s supergiant Majnoon oil field in 2017 and of its withdrawal from Iraq’s supergiant West Qurna 1 oil field in 2018. Each of
Government floats tender to set up 4,50,000 ton green hydrogen production facility in India
Solar Energy Corporation of India (SECI) has floated a tender for setting up a production facility of 4,50,000 tonne of green hydrogen in India under the Strategic Interventions for Green Hydrogen Transition (SIGHT) scheme. SECI is a Government of India enterprise under the administrative control of Ministry of New & Renewable Energy (MNRE). It is a nodal agency for implementing various schemes for renewable energy in the country. According to the tender document, the total capacity available for bidding is 4,50,000 tonne per annum including 4,10,000 tonne under Technology Agnostic Pathways and 40,000 tonne under Biomass Based Pathways. The total capacity to be allocated under this tender is 450,000 tonne per annum of green hydrogen (GH2), it stated. It provided that a bidder, including its parent, affiliate or ultimate parent or any group company shall submit a single bid undertaking to set up a GH2 production facility. The projects shall be quoted in multiples of 500 tonne only, it stated