LNG Market Grows More Mature, But Supply Risks Remain
European gas prices spiked earlier this month as workers at three LNG facilities in Australia threatened industrial action. Strikes were avoided at one of the facilities, but the danger remained for the other two, keeping a floor under gas prices. But over the past year, attempts have been made to put a sort of a ceiling on gas prices in Europe—and more specifically, LNG prices. The effort is beginning to pay off. Until last year, the global LNG market featured long-term contracts indexed to crude oil futures prices, and spot deals. After Russia invaded Ukraine, the EU started shooting sanctions, and pipeline gas flows began to shrink, LNG suddenly became extremely important for Europe. And that prompted a race to lower the pricing risks associated with the state of the LNG market at the time. That race resulted in the launch of the Northwest European LNG futures contract based on the S&P Global NWM, or Northwest Marker. The LNG market matured fast. Traders in an extremely volatile market could hedge European LNG cargos. They could also no longer care so much about pipeline gas and its price when trading LNG. The reason, once again, was the market disruption caused by the Ukraine conflict, chief among them the decimation of gas flows from Russia, especially after the sabotage of the Nord Stream pipeline. A mature market is a lower-risk market, and this is what has been happening to the LNG market over the past year and a half. This, however, has not really reduced the extent of volatility in that market, as evidenced by the effect that news of the potential strikes at Australia’s top three LNG facilities had on LNG prices, especially in Europe. Hedging is important in trade, but when there is a danger of a supply shortage, all bets are off. And there was a danger of a supply shortage equal to a tenth of total global supply—this is how much the North West Shelf, Gorgon, and Wheatstone produce together. Ultimately, supply and demand continue to trump any other factors traders might use to reduce risks inherent in commodity markets. No doubt, it is good to have a liquid market, and now, thanks to the rise of the Dutch benchmark TTF at the expense of the UK’s National Balancing Point, LNG traders have such a liquid market. Trade is more active than ever and easier than ever, even intercontinental trade with Asia. At the same time, however, prices, whatever benchmark they are based on, remain supersensitive to the threat of potential outages. The good news is that perhaps a repeat of last year’s price spikes may be less likely this year or in the future because of the maturing LNG market. On the other hand, tight supply, in case of a cold Northern Hemisphere winter, could push prices significantly higher during peak demand season. The good news, for now, is that Europe’s gas storage is fuller than usual for this time of the year. Thanks to leftover volumes from last year, which were bought at record prices, and it made no sense to resell them at a huge loss, the continent’s storage is now 92.5% full. This could provide a comfortable buffer in case of an outage, especially if the outage does not last very long. Even with this buffer, however, Europe will continue to be a major rival for Asia in LNG cargos as it has been forced to reduce its reliance on pipeline gas. Demand from Asia is already picking up ahead of the winter season. This season will probably be the first big trial for the new, more mature, global LNG market.
Turkmenistan’s Natural Gas Boom Sparks European Interest
Turkmenistan’s huge gas reserves have been generating considerable interest from potential importers following Ashgabat’s announcement in late July that it is open to the development of a pipeline to carry its gas across the Caspian and on to Europe. Most significant so far has been the interest shown by Hungary, which on August 20 signed a framework gas supply agreement with Turkmenistan, during a state visit to Budapest by Turkmen President Serdar Berdymukhamedov. Also in Budapest for meetings with Hungarian leader Viktor Orban were Turkish President Recep Tayyip Erdogan – who was there to oversee the signing of a gas supply agreement between Turkey’s state gas import-export and transit company Botas and Hungary’s state power company MVM for 300 million cubic metres a year of gas – and Azerbaijani President Ilham Aliyev, whose state oil company SOCAR is already supplying MVM with 1 billion cubic metres a year of Azerbaijani gas. For Hungary and the EU, these three agreements are significant as they signal that the central European state is preparing for a future without guaranteed gas supplies from Russia, which is currently Hungary’s main supplier and with which Budapest continues to enjoy cordial relations. However, flows of Russian gas, which arrive via Ukraine are set to stop by the end of 2024 with Kyiv having signalled its unwillingness to renew the existing transit agreement with Moscow – an understandable move given Russia’s ongoing invasion. For Turkmenistan, the agreement is the most concrete evidence so far that Europe is serious about receiving gas from Turkmenistan’s vast reserves in place of Russian gas, imports of which have all but halted since Russia’s invasion of Ukraine early last year. How much Turkmen gas Hungary will import, how the gas will be delivered, and when supply will commence, have not been made clear. With no pipeline yet developed to carry gas from Turkmenistan across the Caspian, the only route currently open would be via the three-way gas swap deal between Turkmenistan, Iran and Azerbaijan first agreed in late 2021, and recently expanded. Under that agreement Turkmenistan sends its own gas to northeastern Iran, which then transits the same volume of its own gas on to Azerbaijan, enabling Baku to meet its own growing gas demand and existing gas export agreements while freeing up further volumes of Azerbaijani gas for onward transit to Europe. Although cumbersome, the three-way swap has been operating successfully since January last year and was recently expanded from 4.5 million cu m/day to 8 million cu m/day with plans to expand it further to 10 million cu m/day. Gas sold by Turkmenistan could be transited from Azerbaijan using spare capacity in the three pipelines which make up the Southern Gas Corridor that currently carries Azerbaijani gas to Georgia, Turkey and on to Europe. In July last year, Azerbaijan signed a memorandum of understanding with the European Union under which it undertook to double the volume of gas it sends to Europe to “at least 20 billion cu m/yr” by 2007. However, it is still unclear whether Azerbaijan will be able to double its own gas production by then, with the Turkmen-Iran swap agreement currently the most likely source of gas to fill any gap. Iran stands to also be the route to another gas-hungry market interested in importing Turkmen gas, namely Iraq. The oil-rich Middle Eastern state also has large gas reserves of its own but decades of political instability and the high cost of developing the fields have so far prevented the investment necessary to bring them to market. Baghdad has for some years been importing gas from Iran to generate electricity, but maintaining steady supplies has been difficult due to difficulties transferring payment caused by the ongoing US sanctions against the Islamic Republic, as well as Iran’s own periodic problems meeting domestic demand. A preliminary agreement between Baghdad and Ashgabat signed on August 24 is expected to be followed by the end of this year with a formal agreement detailing volumes and transit details, which are expected to involve some form of barter arrangement which will avoid the necessity of transferring money to Tehran. Turkey and Azerbaijan key to bringing Turkmen gas to market Swap deals transferring gas via Iran are feasible for the small volumes of gas expected to be involved in agreements with Hungary and Iraq. But with gas reserves estimated at between 10 and 14 trillion cubic metres, the main focus of interest in Turkmenistan remains its potential to replace the Russian gas that has all but stopped flowing to Europe since Russia’s invasion of Ukraine. Any significant gas transit from Turkmenistan will require the development of a whole new pipeline infrastructure crossing the Caspian Sea and running through Azerbaijan, Georgia Turkey and the Balkans to connect with the existing central European pipeline network which, with no Russian gas, has the necessary spare capacity. Azerbaijan has already signalled its interest in hosting such a transit line but has warned it is unwilling to bear any of the cost. Turkey too has frequently signalled interest in transiting Turkmen gas to Europe. In May Ankara issued a new 10-year import license to state gas importer Botas, for the import of up to 16 billion cu m/yr of Turkmen gas under a contract signed in the late 1990s, but never implemented it due to the lack of a pipeline. Whether the development of such a pipeline is getting any closer is the subject of considerable interest in Europe. Certainly, the presence of Turkmen President Serdar Berdymukhamedov, Turkish President Tayyip Erdogan and Azerbaijani President Ilham Aliyev, all in Budapest at the same time provided the opportunity for high-level talks. An opportunity noted by Hungarian president Viktor Orban who, referring to his visitors, posted on X, “That’s what I call connectivity.”
Evading primary responsibility, ONGC decides to invest Rs 150 billion in sick subsidiary
It is reported that Oil and Natural Gas Corporation (ONGC) will infuse about Rs 150 billion in ONGC Petro-additions Ltd (OPaL) as part of a financial restructuring exercise. ONGC currently holds 49.36 per cent stake in (OPaL), which operates a mega petrochemical plant at Dahej in Gujarat. GAIL (India) Ltd has 49.21 per cent interest and Gujarat State Petrochemical Corporation (GSPC) has the remaining 1.43 per cent. OPaL is reported to have incurred losses in the past due to lopsided capital structure with high-debt servicing cost. It is said that cost overrun due to delay in implementation of project is the primary reason for it incurring losses . Obviously, delay in implementation and commissioning of the project must have happened due to various reasons and perhaps, including some hidden reasons which have not been shared adequately. Accumulated losses touched Rs 130 billion on 31st March 2023. As noted by the company’s auditors, OPaL is “facing negative working capital of Rs 70.750 billion as of that date. Net worth of the Company has reduced to Rs 6,207.99 million as at March 31, 2023 as compared to Rs 45,837.20 million as at March 31, 2022. In spite of these events or conditions which may cast doubt on the ability of the company to continue as a going concern, the management is of the opinion that going concern basis of accounting is appropriate in view of the cash flow forecasts and the plant management has put in place along with other facts.” ONGC’s proposal It is reported that ONGC would make additional investment that would convert Opal into virtually a subsidiary of ONGC. While ONGC would spend Rs 150 billion in OPaL, there is no information in the public domain as to what would be the strategy to revamp the unit and place it on the path of profitability. This information is particularly necessary, since the product range of OPaL are extremely important and apparently there are no technical snags in operating the projects. Mere change of product mix by OPaL as part of revamping plan will not provide any significant reduction in loss.
Italy’s Eni looks to sell LNG in Southeast Asia, may introduce US LNG into portfolio
Italy’s Eni is looking to sell LNG into Southeast Asia to tap new emerging buyers and it may also consider introducing more US LNG into its portfolio to diversify its volumes, Cristian Signoretto, deputy chief operating officer natural resources and director global gas & LNG portfolio, told S&P Global Commodity Insights in an interview. There is a lot of potential demand in Southeast Asia due to a number of reasons — floating regasification technology has made it much easier to get access to LNG compared to an onshore facility that would cost more and take very long to build; and the countries have to substitute coal with gas in order to reduce the use of polluting fuels, he said. “So they are coming into the market. And this is a good niche opportunity for portfolio players and producers. We are actively marketing our volumes in those countries,” Signoretto said. While Southeast Asian demand is much lower than South Korea, Japan or China, the region opens up multiple opportunities, he said. “So this is definitely a trend that is expected to increase.” Signoretto said emerging buyers usually have national utilities that provide sovereign guarantees which helps facilitate transactions, although the smaller energy players can be more of a headache, when asked about the challenge of dealing with new buyers with low credit worthiness. “With LNG you can take a bit more risk [compared to pipelines] in the sense that if for some reason the counterparty does not honor the contract, you still can move the LNG somewhere else,” he added. Signoretto also said India is a very cautious buyer of gas as the right price is needed to displace other fuels in the country, and at around $15-$16/MMBtu, the country refrains from buying LNG because it’s too expensive. “They can use other fuels,” he said. Meanwhile, China’s heating demand is a bit inflexible and inelastic because heating systems are switched to gas, its tough to go back to fuel oil or coal, he said. China is increasing the penetration of gas in industrial and power sectors, but they also have access to other sources like piped gas from Russia and Central Asia, although the country has a slightly higher price tolerance for LNG, Signoretto said. Eni has plans to expand its contracted LNG portfolio to over 18 million mt/year by 2026, from around 10 million mt/year, which will help replace around 20 billion cubic meters of lost Russian gas by 2025. Most of this is expected to come from equity projects in Congo, Mozambique, Nigeria and Qatar. In Mozambique, Eni recently developed the Coral Sul floating LNG project and the company is now working on a second floating LNG project in the country, Signoretto said.
Diesel sales fall in September amid rains, petrol consumption up in India
Diesel sales in India fell for the second straight month in September as rains dampened demand and slowed industrial activity in some parts of the country, preliminary data of state-owned firms showed. While diesel sales by three state-owned fuel retailers fell year-on-year in the first half of September, petrol sales were up marginally. Consumption of diesel, the most consumed fuel in the country accounting for about two-fifths of the demand, fell 5.8 per cent to 2.72 million tonnes between September 1 and 15, compared to the year-ago period. Consumption had fallen by a similar proportion in the first half of August. Month-on-month sales were up 0.9 per cent, when compared with 2.7 million tonnes of diesel consumed in the first half of August. Diesel sales typically fall in monsoon months as rains lower demand in the agriculture sector which uses the fuel for irrigation, harvesting and transportation. Also, rains slow vehicular movements. Consumption of diesel had soared 6.7 per cent and 9.3 per cent in April and May, respectively as agriculture demand picked up and cars yanked up air-conditioning to beat the summer heat. It started to taper in the second half of June after the monsoon set in. It fell in the first half of July but picked up in the second fortnight of that month. Petrol sales were up 1.2 per cent to 1.3 million tonnes in the first fortnight of September, when compared with the same period last year.
Rajasthan CM Approves Draft Of Green Hydrogen Policy
The state government has announced “Rajasthan Green Hydrogen Policy-2023”, keeping in view clean energy production, future energy needs, and climate change. Chief minister Ashok Gehlot has approved the policy draft and the notification will be issued soon by the energy department, said a government statement on Saturday. Under this policy, companies producing green energy in the state will get various types of incentives. Green hydrogen is produced by electrolysis of water using renewable energy. The main use of green hydrogen is in refinery, steel plants, and manufacture of ammonia. The state government will provide various facilities to investors under the policy. These include 50 per cent rebate in transmission and distribution charges for 10 years for 500 KTPA (kilo-tonnes per annum) renewable energy plants to be installed on the state’s transmission system. The state government has set a target of 2000 KTPA energy production by the year 2030 in the policy.
India raises windfall tax on petroleum crude to Rs 10,000/tonne
India’s government has increased the windfall tax on petroleum crude to Rs 10,000 per tonne from 6,700 rupees per tonne, according to a government notification on Friday. The increase will come into effect from Sept. 16. The government has cut the windfall tax on aviation turbine fuel to 3.50 rupees per litre from 4 rupees per litre.
Gas migration case: What exactly is the dispute between Reliance and ONGC?
A division bench of the Delhi High Court on Thursday sought a response from Reliance Industries Ltd. (RIL) and its partners on the government’s appeal that accused the Mukesh Ambani-owned conglomerate and its partners of committing an “insidious fraud” and “unjust enrichment of over $1.729 billion” by siphoning gas from deposits they had no right to exploit. The dispute over the gas migrating from ONGC’s block to the adjacent block of RIL and its partners dates back to 2014, and has been through several judicial and arbitration processes. How it all started In 2014, state-run ONGC approached the court, complaining that gas from its blocks was being produced by RIL. ONGC claimed that RIL had deliberately drilled wells close to the common boundary of the blocks and that some gas it pumped out was from its adjoining block. RIL is the operator of the said KG-D6 block with 60 per cent interest while BP holds 30 per cent. The remaining 10 per cent is with Niko Resources. ONGC claims that RIL has benefited from gas flow between their adjacent fields during the 2009-2013 period and took RIL to court over the matter. RIL maintained that it had followed the Production Sharing Contract in letter and spirit and done no wrong. It has drilled all wells within its boundary walls. The two companies appointed US-based consulting agency DeGolyer and MacNaughton (D&M), to examine the issue. D&M said that natural gas worth over Rs 11,000 crore had migrated from idling KG fields of the state-owned firm to the adjoining KG-D6 block of RIL. The Justice Shah committee report After the consultant’s report, a committee was set up under Justice A.P. Shah in 2015 to quantify unfair enrichment, if any, by RIL and to recommend ways to compensate ONGC and the government. The Justice Shah Committee opined that RIL should pay the government for the natural gas it has drawn from an adjacent block of ONGC in the KG basin of the Bay of Bengal in the past seven years. The arbitration panel rejects govt contention The Oil Ministry in November 2015 issued a notice to RIL, Niko and UK’s BP Plc seeking $1.47 billion for producing in the seven years ended March 31, 2016 about 338.332 million British thermal units of gas that had seeped or migrated from the state-owned ONGC blocks into their adjoining KG-D6 in the Bay of Bengal. After deducting $71.71 million royalty paid on the gas produced and adding an interest at the rate of Libor plus 2 per cent, totalling $149.86 million, a total demand of $1.55 billion was made on RIL, BP and Niko. In 2016, RIL-BP-Niko sent an arbitration notice, thereby showing intent of quickly resolving the sticky issue. Next year, a three- member arbitration panel was set up to judge the validity of the government’s demand of $1.55 billion compensation from Reliance Industries for “unfairly” producing ONGC’s gas. Favouring RIL-led consortium in the so-called gas migration dispute case, the three-member tribunal headed by Singapore-based arbitrator Lawrence Boo in its 2:1 award in 2018 rejected the government’s contention. It said that the production sharing contract (PSC) doesn’t prohibit the contractor from producing gas—irrespective of its source—as long as the producing wells were located inside the contract area. It also had held that the consortium was not liable to pay any amount to the government and had also directed the latter to pay $8.3 million as the cost of arbitration to the consortium. The government moves court Soon after, the government moved the court, seeking setting aside of the arbitration award on the grounds that “the award strikes at the heart of the public policy and has given a premium to a contractor (RIL) that has amassed vast wealth by committing an insidious fraud as well as criminal offence …” “The unjust enrichment amassed by the contractor had already reached more than $1.729 billion today (at the time of filing petition), and is since increasing as the production of migrated gas is still continuing,” it had stated in its petition. On Thursday, September 14, Delhi High Court’s division bench sought a response from Reliance Industries and others on the government’s appeal. Attorney General R Venkentaramani and former AG KK Venugopal, appearing for the government, argued that RIL in 2003 knew about the connectivity of its block with that of the adjoining ONGC block. They also accused RIL of ‘consciously and deliberately’ extracting and selling the adjoining ONGC gas without the government’s knowledge. The senior lawyers also argued that RIL had earlier taken a categorical stand that “there is no connectivity and continuity” between RIL’s and ONGC’s block. And the impugned arbitral award is in conflict with the public policy of India, they added. RIL through counsel Sameer Parekh opposed the government’s appeal, arguing that these issues cannot be reopened under Section 37 of the Arb Act. Public trust doctrine and other points raised by the govt have been looked into both by the arbitral tribunal as well as the single judge. Citing the director general of hydrocarbons report, the lawyer argued that the study of migration of gas could have been done by the ministry in 2009 itself, much before the gas block was given to RIL, but the ministry chose not to do so. The adjoining ONGC gas block was underdeveloped when RIL started extracting gas and it would have been “infeasible” to extract gas from the ONGC’s block which was at a different stage of development then, it said.
Air Fares Poised To Skyrocket As EU Adopts Green Fuels For Aviation
Back in 2008, Virgin Atlantic made history after flying a Boeing 747 between London and Amsterdam partly powered by a biofuel made from Brazilian babassu nuts and coconuts. Although Virgin Atlantic founder Sir Richard Branson hailed the event as a “vital breakthrough”, many people dismissed it as just another one of his marketing stunts. And they were right. In November 2023, Virgin Atlantic will operate the world’s first transatlantic flight powered entirely by green aviation fuels in yet another one-off demo. A decade and a half since Virgin Atlantic’s 2008 demo, only five airports have regular biofuel distribution today (Bergen, Brisbane, Los Angeles, Oslo and Stockholm). On a global level, aviation biofuels account for less than 1% of the 1.5 billion barrels of aviation fuels, or ~15% of global oil supply, that commercial airlines burn through in a typical year. Indeed, the global aviation industry is a leading polluter; it would rank among the top 10 emitters if it were a country. But this is about to change in Europe. On Wednesday, EU lawmakers approved new rules that require at least 2% of jet fuel used by airlines to be sustainable as of 2025, with that share to increase every five years to hit 70% by 2050. The new legislation is part of the EU ’s “Fit for 55” package, which has set a goal to cut greenhouse gas emissions by least 55% by 2030. Whereas 2% might not seem like much, consider that currently less than 0.05% of Europe’s aviation fuel is sustainable, meaning airlines within the bloc will have to increase their share of clean fuels by more than 40x in the space of just two years. For a sustainable aviation fuel (SAF) to qualify as sustainable, it must be able to cut greenhouse gas emissions by at least 50% compared to conventional fossil fuel-based jet fuels. At the top of the sustainability hierarchy are fuels made from biomass including crop residues, animal waste, forestry residue, algae and even everyday rubbish, such as product packaging and food leftovers that can typically lower CO2 emissions by 85-95%. But achieving cleaner flights will not come cheap. SAF are significantly more expensive than conventional jet fuel, and this cost premium is the key barrier to their wider adoption. Fuel costs constitute the biggest line item for airlines, typically accounting for ~22% of their overheads. Using renewable air fuel would likely necessitate passing the extra costs to customers by increasing ticket prices, something that would not work well unless everybody did it at once because airline-specific fare changes are highly price elastic. The economics of some SAF are just egregious: earlier in the year, Exxon Mobil (NYSE:XOM) pulled the plug on its 14-year-long algae biofuels project because it found that crude would have to hit ~$500/bbl for algae biofuels to compete successfully. Either way, air travel is about to get a lot more expensive, so much so that the “demand reduction impact” that would result from people being priced out is expected to account for ~14% of the required cuts to hit the EU emissions target. Bright Future For Synthetic Fuels The latest move by the EU improves the outlook for synthetic fuels even further. Synthetic fuels are liquid fuels produced from natural gas, coal, peat, and oil shale, and include synthetic diesel, synthetic kerosene and green methanol. According to the IEA, synthetic fuels are vital in the decarbonization of transport and industry by 2050. Carbon-neutral synthetic fuels are manufactured using captured carbon dioxide or carbon monoxide from the atmosphere or an industrial process such as steel making and also from biomass that is gasified before being catalyzed with hydrogen using thermal or chemical means. German multinational engineering and technology company BOSCH is a leading advocate of synthetic fuels. According to the company, synthetic fuels will help the roughly half of the current fleet of vehicles expected to still be on the roads by 2030 to play a part in cutting CO2 emissions (synthetic fuels are 100% compatible with current fossil fuel engines). Synthetic fuels can also be blended in fossil fuels or can completely replace them in existing ships, airplanes or industrial technologies. Studies have found that sustainable aviation fuels including synthetic or bio-based jet fuels, are so far the most promising option for the decarbonization of the carbon-heavy aviation sector. Two years ago, the Netherlands demo’ed the first passenger flight powered by synthetic fuels with an energy density only marginally lower than that of fossil-based kerosene. The IEA has predicted that by 2030, 15% of total fuel consumption in aviation will be SAF, rising to 75% by 2050.
The 5 South American Countries With The Largest Natural Gas Reserves
South America is fast emerging, once again, as one of the world’s hottest drilling locations, with the continent believed to contain considerable volumes of commercially extractable natural gas. While offshore Guyana is garnering the lion’s share of attention from foreign energy companies, it isn’t the only country in South America benefiting from significant hydrocarbon wealth. Argentina, despite its economic woes, is profiting from a massive unconventional hydrocarbon boom that could see the country emerge as a regional natural gas hub, while production from Brazil’s offshore oil fields is growing at a steady clip. These events are challenging South America’s traditional energy dynamics, with Venezuela, Colombia and Bolivia no longer the continent’s leading hydrocarbon producers. Here are South America’s five leading countries by proven natural gas reserves. #5 Peru The troubled Andean country of Peru, which is locked in a lengthy political crisis, possesses the fifth-largest proven natural gas reserves in South America. Those reserves, at the end of 2022, totaled 8.4 trillion cubic feet, which is 19% less than a year earlier and nearly half of the 15.4 trillion cubic feet reported a decade earlier. During August 2022, Peru pumped an average of 1.27 billion cubic feet of natural gas per day, which was 2% higher than a month earlier and a notable 16% greater than the same period during 2022. Those numbers demonstrate Peru is successfully scaling up natural gas output in response to growing domestic energy demand but needs to attract greater investment in hydrocarbon exploration and development to boost reserves. Peru’s hydrocarbon sector has been roiled by crisis and conflict for many years. Frequent anti-government and oil industry protests in Peru’s remote Amazon region have forced the shuttering of oilfields and Peru’s northern pipeline, which connects those fields to the Pacific Coast. Those protests are triggered by the immense environmental damage caused by oil industry operations and the lack of spending by the government in Lima on crucial infrastructure in Peru’s Amazon. This is weighing on Lima’s efforts to attract crucial foreign energy investment needed to boost proven reserves and production. #4 Bolivia Once known as the beating heart of South America’s natural gas industry, Bolivia’s fossil fuel fortunes are fading. It is estimated that the landlocked Andean country has proven natural gas reserves of nearly 9 trillion cubic feet, down from 11 trillion cubic feet a decade ago. That isn’t the only sign of an industry in decline. For June 2023, Bolivia pumped 1.25 billion cubic feet of natural gas per day, which, despite being 3% greater than a month prior, was a worrying 15% lower year over year. Natural gas production has plunged sharply in recent years, with 2022 output of 1.400 billion cubic feet per day 11% lower than 2021 and considerably less than the 1.85 billion cubic feet per day extracted a decade earlier. For these reasons, there is growing uncertainty regarding the future of Bolivia’s hydrocarbon sector, which was once responsible for keeping the lights on in neighboring Argentina. Indeed, Bolivia’s natural gas production has been steadily declining since 2015 and is expected to plunge well below one billion cubic feet per day in coming years due to aging mature gas fields, a lack of discoveries and a dearth of industry investment. Industry analysts believe that the end of the country’s once-mighty natural gas industry is close, with natural gas output expected to decline calamitously over the near-term. According to industry consultancy Wood Mackenzie, Bolivia’s natural gas production could fall to as low as 400 million cubic feet per day by the end of this decade. #3 Argentina In a surprising development, Argentina, which recently avoided yet another sovereign debt default and is struggling with triple-digit inflation, now has the fourth-largest proven natural gas reserves in Latin America. At the end of 2022, data from the Ministry of Economy showed that proven natural gas reserves totaled 15.4 trillion cubic feet, which is not only an 11% increase over a year earlier but a stunning three times greater than a decade earlier. That incredible growth can be attributed to the ongoing exploitation of the Vaca Muerta shale formation, which didn’t start in earnest until 2013 after the government of Cristina de Kirchner nationalized Repsol-owned YPF. The ongoing exploitation of the Vaca Muerta saw Argentina’s natural gas production surge to an all-time high of nearly 5 billion cubic feet per day during August 2022. While output has declined since then, Argentina still lifted an average of 4.9 billion cubic feet for August 2023. Production will keep growing with YPF budgeting investment of $2.3 billion for its shale operations during 2023 with a view to boosting natural gas production by 15% compared to 2022. The Vaca Muerta, with an estimated 16 billion barrels of oil and 308 trillion cubic feet of natural gas, is believed to contain the second-largest shale gas reserves in the world. The ongoing development of the geological formation, which has been compared to the prolific Eagle Ford shale in Southern Texas, will see Argentina emerge as a major hydrocarbon producer and exporter in Latin America. This will allow Argentina to dial down energy imports, especially natural gas from neighboring Bolivia, which will go a long way to reducing a massive trade deficit and repairing a broken economy. #2 Brazil South America’s largest oil producer, Brazil, also possesses the second-largest natural gas reserves on the continent, which total 14.4 trillion cubic feet. Most of those reserves are contained within Brazil’s prolific offshore pre-salt fields and are associated with oil production. During July 2023, Brazil’s hydrocarbon output soared to a record high of 4.48 million barrels of oil equivalent, 78% weighted to oil, which was 3.6% greater than a month earlier and a whopping 17.5% higher year over year. Natural gas output for the month hit an all-time high of 5.4 billion cubic feet per day, which was 1.2% higher month over month and a notable 13.6% greater than a year earlier. Natural gas production in Latin America’s largest economy will continue