ATGL and INOX Partner for LNG in India
Indian city gas distribution company Adani Total Gas Ltd (ATGL) and INOX India Ltd have signed a mutual support agreement for a liquefied natural gas (LNG) partnership. Under the agreement, the two companies have designated each other “preferred partner” status for the delivery of LNG and liquefied compressed natural gas (LCNG) equipment and services. ATGL and INOX will also explore collaboration opportunities for “strengthening the LNG ecosystem in the country”, they said in a joint news release. ATGL will have certain inherent project level benefits, which include preferential treatment and access to advanced scheduling, and consideration for collaborative opportunities for establishing LNG/LCNG stations, LNG satellite stations, transitioning to LNG as a transport fuel, LNG logistics, as well as developing small-scale liquid hydrogen solutions for the industry, according to the release. The agreement covers the role and obligations of both parties to leverage expertise in developing LNG infrastructure, including small-scale LNG plants, LNG stations, bringing economy of scale for conversion of heavy vehicles to LNG, developing best practices towards HSE, fuel efficiency, high quality conversion, and services. “As our economy prepares to go [into] an overdrive, it is imperative that we also maintain a focus on ensuring that the transition happens in a sustainable manner”, Siddharth Jain, non-executive director for INOX, said. “We are, therefore, excited about our cooperation with ATGL, which would look to strengthen the LNG ecosystem and building and promoting LNG as a transport fuel. Our combined synergies, backed by expertise and scale of both the Parties will truly benefit the stakeholders in the economy in reducing emissions, and make significant contributions towards the green transition”.
India’s Natural Gas Consumption Set To Triple by 2050
India’s industry expansion and rising oil refining to meet higher fuel demand are set to drive a tripling of the country’s natural gas consumption by 2050, the U.S. Energy Information Administration (EIA) said on Wednesday. In 2022, India’s natural gas consumption amounted to 7.0 billion cubic feet per day (Bcf/d), with over 70% of the demand coming from the industrial sector. By 2050, India’s natural gas consumption is set to more than triple to 23.2 Bcf/d, according to EIA’s estimates. Among India’s five consuming sectors, the industrial sector’s share of gas consumption will grow the most, rising to 80% of total consumption, followed by the transportation sector rising to 10%. India’s gas consumption in oil refining is expected to grow significantly to keep up with India’s domestic demand for oil products, the EIA notes. By 2050, gas consumption will surge by more than 250% for the production of basic chemicals and by more than 400% for refining, with the two industries together accounting for about 79% of India’s industrial natural gas demand in 2050. India is boosting its refining capacity. The country should add 1.12 million bpd to its current total each year until 2028, a junior oil minister told India’s parliament at the end of 2023. Total Indian refining capacity is expected to increase by 22% in five years from the current 254 million metric tons per year, which are equal to around 5.8 million bpd, Rameswar Teli said. Per the EIA forecasts, India’s gas demand – buoyed by oil refining and other industrial production – is expected to grow at an annual rate of 4.4% by 2050, more than twice the 2.0% annual growth rate of gas consumption in China, the next-fastest-growing country. India’s economy is growing faster than all other major economies, and so is its demand for energy. All forecasters expect India to replace China as the biggest driver of global oil demand growth in the long term, which should happen before 2030.
Shell Lowers LNG Growth View as Demand Set to Peak in 2040s
Shell Plc said that demand for liquefied natural gas by 2040 will be slightly lower than previously forecast as the world is preparing for life beyond fossil fuels. The LNG market “will continue growing into the 2040s, mostly driven by China’s industrial decarbonisation and strengthening demand in other Asian countries,” Shell’s report said. Shell holds the largest gas liquefaction and marketing portfolio among global energy majors, servicing almost 20% of worldwide demand, according to Bloomberg Intelligence.
As U.S. Pauses New LNG Project Permits, Iran Moves Full Ahead On Its Own
Since Russia invaded Ukraine on 24 February 2022, liquefied natural gas (LNG) has become the world’s key emergency energy supply. It does not require the years of planning and construction as pipelined gas and oil, and it can either be secured readily through long-term contracts or bought immediately in the spot market if necessary and shipped anywhere quickly. As such, it has been ideally suited to make up the vast energy supply gaps created due to sanctions on Russian gas and oil. Despite its extremely elevated geopolitical importance – especially for Europe – the U.S. decided to pause permits for its new LNG projects, as analysed in full recently by OilPrice.com. By notable contrast, whilst simultaneously attempting to widen out the Israel-Hamas War into a new global energy emergency, Iran has decided to go full ahead on building out its own long-nascent LNG industry into a world-scale operation, according to recent comments from Tehran. As mentioned by Iran’s Petroleum Ministry at the end of January, the country intends as part of this new drive towards building up its LNG sector, to begin 1.5 million metric tonnes per year (mtpy) of production at a medium-sized plant at Asaluyeh in 2026. As exclusively related to OilPrice.com by a very senior figure who works closely with the Petroleum Ministry, much bigger plans are afoot much earlier. Iran has long been looking at further monetising its huge gas resources – and securing further geopolitical power – by becoming a top global exporter of LNG, as analysed in depth in my new book on the new global oil market order. Its neighbour, Qatar, with which Iran shares the world’s biggest gas reservoir – the North Field (on the Qatar side)/South Pars (on Iran’s side) side – had carved out a dominant position in the global energy market on the strength of those very gas supplies. In the run-up to, during, and since the invasion of Ukraine by Russia, Qatar has even more substantially leveraged its leading LNG exporter status into significant geopolitical influence, becoming a key supplier of China and of the U.S.’s key NATO security allies in Europe as well. A dramatic expansion of Iran’s gas production from the South Pars field to feed growing LNG production needs could well affect Qatar’s gas take from its North Field side of the entire reservoir over time. One of the reasons why Qatar lifted its self-imposed moratorium on North Field gas production in 2017 were confidential field reports over the previous year from the then-Qatargas detailing how “irresponsible drilling practices” by the Iranians posed risks to the long-term gas take for Qatar from the North Field. Just before the moratorium was lifted, the two sides met in Doha to discuss how they would approach their respective gas production operations so that both sides could maximise their overall gas take over the long-term, according to the Iran source. However, Iran could equally well decide in the current circumstances – in which Qatar is increasingly seen as a key ally of the U.S.’s – to revert to its previous gas production techniques at South Pars in order to disrupt Qatari gas flows. In the ‘zero-sum’ world of LNG exports, decreased supplies of LNG from Qatar to Europe, and increased supplies from Iran to China – inevitably given the all-encompassing ‘Iran-China 25-Year Comprehensive Cooperation Agreement’ analysed in depth as well in my new book on the new global oil market order – would be a major win for Beijing, and for Moscow as well. Although the Asaluyeh LNG project will start with just a 1.5 mtpy plant, the Iran source told OilPrice.com last week that it is to be built on the site of the original much-larger ‘Iran LNG Project’ around Tombak Port, around 30 miles north of Asaluyeh itself, focusing on gas from the North Pars gas field. Located 120 kilometres southeast of the southern Bushehr Province, the North Pars field has around 59 trillion cubic feet of gas in place, with a conservatively estimated recoverable volume of gas of approximately 47 trillion cubic feet. The first deal to operate this field had been approved in 1977 but, after the drilling of 17 wells and the installation of 26 offshore platforms, the development of North Pars was suspended due to the 1979 Islamic Revolution and the subsequent war with Iraq from 1980-1988. However, a study of the state of North Pars by Iran at the end of 2020 determined that the field was still in a highly workable state for a quick push to significant gas output. Specifically, it was established, at least 100 million cubic metres per day (mcm/d) of output could be achieved within less than 12 months of proper development – with all the gas recovered to be channeled into LNG production of at least 20 million mtpy. An early entrant to the original Iran LNG Project was the China National Offshore Oil Corporation (CNOOC), which signed a memorandum of understanding (MoU) in September 2006 with the National Iranian Oil Corporation (NIOC) to develop the North Pars gas field with a view to building out an LNG capability there. This deal was extended in December 2006 to incorporate the development of a four-train (LNG liquefaction and purification facility) complex with a 20 mtpy capacity, before slow progress on CNOOC’s part prompted the NIOC to suspend the deal. At that point, just before the U.S. and European Union (E.U.) ramped up sanctions against Iran in 2011/12, German chemicals giant Linde Group took over the main development of the Iran LNG Project. Within a relatively short time, Linde Group had 60 percent-completed the US$3.3 billion flagship LNG export facility that was set to produce at least 10.5 mtpy of LNG, with expectations that it would take less than a year to finish. Again, though, due to further later sanctions, progress on the Project stalled again. With US sanctions firmly back in place in 2018, Russia’s Gazprom which signed two MoUs with the NIOC concerning the rollout
Tankers Tied to the Russian Oil Trade Grind to a Halt Following US Sanctions
A chunk of the vast fleet of tankers that Russia uses to deliver its crude oil is grinding to a halt under the weight of US sanctions, a sign that tougher measures by western regulators might be starting to have tangible effects on Moscow About half of the 50 tankers that the US Treasury began sanctioning on Oct. 10 have failed to load cargoes since they were listed, according to a ship-by-ship tracking of each one by Bloomberg. The latest to be targeted — the Sovcomflot carrier NS Leader — performed an immediate U-turn off the coast of Portugal on Thursday when its owner was named by the US. It was sailing toward a Russian port in the Baltic Sea at the time. The Group of Seven imposed a $60-a-barrel price cap on crude in December 2022 that was meant to keep Russian oil gushing while at the same time depriving the Kremlin of petrodollars. Caps on refined products were introduced two months later. The system came in for heavy criticism last year as Moscow found workarounds and some western companies continued moving the nation’s oil — something they weren’t supposed to do once the barrels traded above the threshold. But the US responded by intensifying sanctions and investigating potential breaches of the price cap, a step that drove many Greek tanker owners out of the trade. The result has been ballooning freight costs and Russian oil that’s being trading at deeper discounts to international benchmarks, according to organizations including the International Energy Agency. Russian energy minister Alexander Novak said that the country’s barrels are going cheaper. The picture is still fragmented because the US Treasury imposed its sanctions in batches, meaning that some ships might not have gotten to the point of loading cargoes yet anyway. Of the 50 tankers sanctioned since early October, 18 have collected cargoes. Of those, nine were shuttle ships and nine appeared to collect consignments as normal since they were added to the list. One is still carrying a cargo it took on board before it was sanctioned. That leaves 31. Of those, seven had been idled even before sanctions and three may well load soon. That leaves 21 that haven’t loaded cargo since. Sanctioned Ships Eight individual vessels were named between Oct. 10 and Dec. 12. Another 24 tankers were then listed on Dec. 20, when the Treasury took measures against SUN Ship Management D Ltd., a company owned by Russia’s state-controlled shipping company Sovcomflot PJSC. Hennesea Holdings Ltd., a United Arab Emirates-based owner of 18 vessels was added to the sanctions list on Jan. 18. The 50th vessel, the NS Leader, was named on Thursday.
Rs 18.63 billion Dividend tranche from GAIL to Central government
GAIL India Dividend 2024: The central government has received a dividend tranche of about Rs 18.63 bn from GAIL (India) Ltd, informed the secretary at the Department of Investment and Public Asset Management through its X handle on Monday, February 12. Incorporated in the year 1984, GAIL it is engaged in the business of oil refining and marketing. Dividend refers to a reward, cash or otherwise, that a company provides to its shareholders. Dividends can be issued in various forms, such as cash payment, stocks or any other form.
U.S. Oil Inventories Rise, Gasoline and Distillate Stocks See Strong Draws
Crude oil inventories in the United States rose by 8.52 million barrels for the week ending February 9, according to The American Petroleum Institute (API), after analysts predicted a build of 2.6 million barrels. The API reported a 674,000-barrel rise in crude inventories in the week prior. On Tuesday, the Department of Energy (DoE) reported that crude oil inventories in the Strategic Petroleum Reserve (SPR) rose by 0.8 million barrels as of February 9. Inventories are now at 358.8 million barrels. Oil prices were up ahead of the API data release on persistent tensions in Russia and the Middle East but capped by new data showing that inflation remained high in January, which could delay Fed rate cuts. At 4:01 pm ET, Brent crude was trading up 0.74% on the day at $82.61, up $4 per barrel from this time last week. The U.S. benchmark WTI was trading up on the day by 1.08% at $77.75, also up $4 per barrel compared to this time last week. Gasoline inventories saw a significant drawdown this week, falling by 7.23 million barrels, more than offsetting the 3.652 million barrels rise in the week prior. As of last week, gasoline inventories were about 1% below the five-year average for this time of year, according to the latest EIA data. Distillate inventories also fell this week, by 4.016 million barrels, on top of last week’s 3.699 million barrels drop in the week prior. Distillates were already 7% below the five-year average for the week ending February 2, the latest EIA data shows. Cushing inventories rose by 512,000 barrels after rising by 492,000 barrels in the previous week.
Red Sea Crisis Is Tightening Oil Markets
Disruptions to shipping in the Red Sea and via the Suez Canal are raising the prices of African and U.S. crude grades and expanding the backwardation in the global Brent crude benchmark, signaling tightening markets and a run-up in diesel prices in Europe. Europe, which has been left exposed to more crude and fuel supplies from the Middle East and Asia since the embargoes on Russian petroleum took effect early last year, now finds itself looking for deliveries from nearby exporters. Growing volumes of petroleum products are now bypassing the Suez Canal – the shortest route from Asia and the Middle East to Europe – and are heading on the longer route via the Cape of Good Hope in Africa, which delays planned deliveries and raises shipping costs. As a result, Europe is buying more U.S. and West African crude. Increased appetite for the so-called Atlantic barrels in Europe is driving the price of Nigerian and U.S. crude grades and is steepening the backwardation in Brent Crude futures, traders tell Bloomberg. Backwardation typically occurs at times of market deficit, and in it, prices for front-month contracts are higher than the ones further out in time. The deeper backwardation curve suggests the market is tightening, analysts say, noting that the supplies may be tighter than market sentiment and price action in oil imply. Analysts expect drawdowns in global stocks this month and next to support oil prices. But they are unsure how long the tightness could persist, as factors including spring refinery maintenance, concerns about demand, and the upcoming OPEC+ decision on extending the cuts – or not – could all upend the current market supply-demand balances. Higher Atlantic Basin Crude Prices As Europe is looking to purchase crude that would travel shorter and safer delivery routes, the prices of Egina and Forcados, key Nigerian grades, have risen in recent weeks. The two West African crudes are now being offered at higher premiums to Dated Brent compared to the premiums from a month ago, according to Bloomberg’s estimates. U.S. grade WTI Midland is also in high demand in Europe, and the crude price has increased compared to the North Sea benchmark in recent weeks. According to Bloomberg’s trading sources, French supermajor TotalEnergies has been bidding nearly every day for WTI Midland supply in a pricing window since the beginning of February. Diesel Tightness Diesel supply is also tight in Europe, partly due to the Red Sea shipping disruptions and lower European refining capacity with some refinery closures and refinery maintenance in the spring. The premium of diesel over crude has surged in recent days to the highest level for this time of year in more than a decade—since 2012. Due to the Red Sea disruption of flows to Europe and spring refinery maintenance, “We expect to see a fall in northwest Europe diesel/gasoil stocks over the next two months,” Wood Mackenzie analyst Emma Howsham told Bloomberg. Diesel prices in Europe started rallying last month amid tightening supply due to Red Sea shipping disruptions, threatening to test the resilience of European economies that have narrowly avoided recessions in recent months. “The European middle distillate market has been plagued by tightness since Russia’s invasion of Ukraine, which has resulted in drastic shifts in energy flows with the EU banning Russian crude oil and refined products. This has left Europe more dependent on Asia and the Middle East for flows, and these flows are being affected by the Houthi attacks in the Red Sea,” ING strategists Warren Patterson and Ewa Manthey wrote in a note on Tuesday. Middle distillates, including diesel, are likely to remain well supported in the short term as refineries go into maintenance season, they added. Tighter Crude Oil Market The prompt Brent time spread weakened on Monday, but the trend this year “has been for the spread to move into deeper backwardation, suggesting that the market is tightening,” ING’s strategists said. The oil market will see marginal tightening with a relatively small deficit this quarter, but this could flip into a surplus in the second quarter if OPEC+ fails to roll over part of its cuts beyond Q1, according to ING. Saxo Bank expects Brent and WTI to remain range-bound in the first quarter at around $80 and $75 a barrel, respectively. However, “disruption risks, OPEC+ production restraint, a tightening product market and incoming rate cuts potentially leaving the risk/reward skewed slightly to the upside,” Saxo Bank’s Head of Commodity Strategy, Ole Hansen, said at the end of last week. Distillate supplies have been disrupted by lower supply from Russia amid Ukrainian attacks on Russian refinery infrastructure and Houthi attacks on vessels in the Red Sea and the Gulf of Aden, Hansen noted. In crude markets, global supply is showing signs of tightness as total exports dropped in January compared to December by the largest amount since August 2023, while global onshore inventories continued to fall, according to Vortexa. Excluding Iran and Venezuela, total crude and condensate exports fell month-on-month by more than 700,000 barrels per day (bpd) in January, marking a steep decline after a brief uptick in December, Jay Maroo, Head of Market Intelligence & Analysis (MENA) at Vortexa, wrote in an analysis last week. Significant drawing of inventories is still taking place, suggesting that “wider macroeconomic concerns, and its impact on demand, is being outstripped by tighter prompt availability,” Maroo noted. “Looking ahead, given market expectations that OPEC+ production will remain constrained, the near-term outlook for crude prices could be more supportive than current sentiment suggests, even with strong signs of weakening global product demand.”
HFE pioneers green hydrogen exploration in India
Srivatsan Iyer, Global Chief Executive Officer of Hero Future Energies (HFE), the renewable energy division of the Hero Group, announced that the company is aggressively investigating prospects for green hydrogen projects in India. To explore several green hydrogen project options, the company is interacting with a range of customers throughout India. Announcements are expected in the upcoming months. HFE made it clear that it has no intention of making green hydrogen electrolysers. The company will continue to source electrolysers from the market, utilising the best available technology, even if it recently signed a strategic memorandum of understanding with Bangalore-based Ohmium, an electrolyser firm. Ahmium International and HFE are working together to build 1,000 MW of green hydrogen production plants in Europe, the UK, and India. With a further 2 GW of projects in the works, the business presently boasts a global portfolio of 3 GW of renewable energy assets. Srivatsan Iyer highlighted the necessity of demand mandates while expressing optimism on this year’s budget allocation for green hydrogen. In order to stimulate the industry, he recommended that the government take into account enacting levels of demand requirements. The high cost of green hydrogen relative to conventional sources is currently deterring large customers in sectors like fertilisers and refineries from adopting it. Reducing costs and hastening the adoption of green hydrogen could be achieved through more demand-driven adoption. Iyer suggested two options for providing green hydrogen to the general public. One is integrating it gradually into the city gas distribution system while safety regulations are being developed. The other is the use of green hydrogen for heavy-duty mobility, such as converting long-distance trucks or buses with internal combustion engines to run on hydrogen fuel.
GAIL, IGL walk away with Reliance gas; bid at USD 11 per million BTU
State-owned gas utility GAIL (India) Ltd and the nation’s largest city gas operator Indraprastha Gas Ltd have walked away with most of the coal seam gas that Reliance Industries Ltd auctioned, sources said. Reliance earlier this month conducted an e-auction for sale of 0.90 million standard cubic metres per day of gas it will produce from coal-bed methane (CBM) block SP (West)-CBM-2001/1 in Madhya Pradesh. Users have been asked to quote a premium they are willing to pay over and above 12.67 per cent of the dated Brent crude oil price, according to a tender floated by the company. The auction saw GAIL and IGL walk away with most of the gas, offering as much as USD 11 per million British thermal unit price, two sources with direct knowledge of the matter said. GAIL won 0.63 mmscmd of gas in the auction while IGL picked up 0.14 mmscmd, they said. In the auction, the gas price was set as higher of 12.67 per cent of dated Brent plus premium ‘V’; or the government-declared monthly price for conventional gas. The government-mandated price for January is USD 7.85 per mmBtu. While Reliance had set the starting bid price of ‘V’ at USD 0.50 per mmBtu, bidders quoted USD 0.78 to walk away with the coal bed gas, they said. At the current Brent crude oil price of USD 80 per barrel, the gas price comes to USD 11 per mmBtu (12.67 per cent of USD 80 is USD 10.1 per mmBtu. Added to this is the bid value of ‘V’ of USD 0.78, which takes the gas price to USD 10.9 per mmBtu). The e-auction happened on February 2. The gas supply in the contract is for 1 to 2 years beginning April 1. The pricing Reliance is seeking is modified from the March 2022 auction. In that auction, it had sought bids at a premium over the base of 13.2 per cent of Brent crude oil price. In March 2022, Reliance sold 0.65 mmscmd of CBM at a USD 8.28 per mmBtu premium over the prevailing Brent crude oil price. Brent oil was trading above USD 115 per barrel at that time. It has now slipped to USD 78 a barrel. Last month, state-owned Oil and Natural Gas Corporation (ONGC) sought a premium over the government-dictated gas price of USD 7.82 per mmBtu for the gas it plans to produce from a CBM block in Jharkhand. ONGC sought bids from users for the sale of 0.05 mmscmd of gas from the North Karanpura coal-bed methane (CBM) block in Jharkhand for three years. Users were asked to quote a premium they are willing to pay over and above the monthly domestic natural gas price that the oil ministry’s Petroleum Planning and Analysis Cell (PPAC) notifies, the tender document showed. PPAC every month declares a price for the majority of domestically produced natural gas. This price is 10 per cent of the monthly average of the basket of crude oil that India imports. For the month of February, this price comes to USD 7.85 per million British thermal units. This price in the ONGc tender was marked as a reserve gas price. While the government sets prices for two-thirds of the gas produced in the country, CBM gas enjoys pricing freedom where sellers are allowed to discover the market rate. Gas extracted from below ground is used to produce electricity, make fertilisers or turned into CNG for sale to automobiles and piped to household kitchens for cooking purposes.