China Seeks Cheap Spot LNG Supply as Prices Dip to Three-Year Low
Chinese LNG importers are on the lookout for cheaper supply of liquefied natural gas on the spot market as prices in North Asia have halved from October levels and slid to a nearly three-year low last week, traders familiar with the deals told Bloomberg on Thursday. Shenzhen Energy Group and China Gas Holdings Ltd have entered into talks with potential suppliers for more spot LNG cargoes for the coming months, while China Resources Gas Group has bought a shipment for delivery in the middle of March, Bloomberg’s sources said. China – the world’s top importer of the fuel after outstripping Japan, again – has returned to the spot market in search of cheaper LNG supply as prices tumble. Currently, spot LNG supply is competitive with local gas and oil products, according to Bloomberg’s sources. As natural gas inventories in Europe and Asia are at comfortable levels for a winter season, and demand is tepid in both continents, the average spot LNG price for April delivery into Northeast Asia plunged by 7.4% last week to $8.80 per million British thermal units (MMBtu), according to estimates from industry sources quoted by Reuters. That was the lowest Asian spot LNG price since the end of April 2021. Demand was weak in the past two weeks even in China, due to the Lunar New Year holiday, and overall demand in Asia is lower amid high inventories both in Asia and in Europe. As a result, spot LNG prices in Asia have now halved compared to the levels from October 2023, just before the 2023/2024 winter began. As the winter season in the northern hemisphere is drawing to a close, spot LNG prices are expected to further slide into the spring, analysts say. Chinese LNG imports have recovered from a decline in 2022 when a spike in prices and Covid restrictions hit demand, but they are still lower compared to the levels seen in 2021.
Natural Gas Price Drop Could Spell Doom for Producers
Natural gas prices have continued to fall, with a mild winter and overproduction that has seen producers in the American shale patch attempt to dial down output only to have oil companies producing gas as a byproduct throw a spanner in the plans. For commodities traders, the floor is probably around $1.50, with February prices now under $1.70 per MMBtu. This situation prompted Chesapeake Energy in its earnings report earlier this week to announce it would reduce its drilling rigs to lower production. Natural gas futures received a bump from that move, but were still hovering in the $1.66 range on Thursday afternoon, and down over 5% on the day. El Niño is a key culprit, weakening trade winds and pushing warm water toward the west coast, resulting in warm weather conditions that reduce the need for natural gas for heating. In the mid-1990s, El Niño caused a major slump in natural gas prices that led to significant layoffs, restructurings and mergers in the industry. Between 1986 and 1995, there were three El Niño winters–all of which coincided with low Henry Hub prices, but also with industry restructuring, according to historical research published by Offshore Magazine in the ‘90s. Since the shale boom in the U.S., this has become more complicated to deal with, with purely gas producers and oil producers producing gas as a by-product not necessarily on the same page in terms of output goals. While Reuters points out that American gas producers have been trying to stem output for a year, their counterparts in the oil patch have not played along. Last year, Reuters reports, U.S. gas firms slashed drilling by 22%; yet, the country is expected to produce 105 billion cubic feet per day this year–an increase of 2.5 billion cubic feet per day on an annual basis. In 2022, the average price of natural gas in the U.S. was $6.50 per million British thermal units. This year, it’s only a fraction of that. But while natural gas prices have shed 75% in the U.S., the West Texas Intermediate (WTI) U.S. crude benchmark has fared much better. The average WTI price for 2022 was $94.9 per barrel. Today, it’s $78.90, reflecting a loss of less than 20%. The main reason for the disconnect here is because there is a cartel interfering in oil prices, while there is none for natural gas. Global supply cuts by OPEC producers keep oil prices in check, while U.S. oil companies who produce gas as a byproduct are “relatively insensitive to prices”, Reuters cited Northern Oil and Gas GEO Nicholas O’Grady as saying earlier this week, adding that gas producers are also hesitant to reduce output because of the attractive prospects for feeding into new LNG plants in the future. The natural next leap in that line of thinking is that when all these new LNG projects launch, the high volume of exports would bring U.S. inventory back down to a level that gas companies can start thinking about big profits. It’s a longer-term game that is also now in flux in the aftermath of the Biden administration’s pause on new LNG projects.
ONGC slow on exploring reserves
A lone international contractor hired to delineate hydrocarbons in Bangladesh’s offshore blocks did little over the past two years, while the country suffers fuel shortages, sources say. India’s oil-and-gas-exploration company named ONGC Videsh Ltd (OVL) is currently the only international oil company (IOC) that has rights to explore untapped offshore in some blocks in the Bay of Bengal, says a senior Petrobangla official. “But, after a ‘failed’ attempt at Kanchan gas-well under the SS-04 block in Moheshkhali Island a couple of years back, the Indian company did not move forward with its exploration works,” he adds. The tenure of its production-sharing contract (PSC) with Petrobangla is set to expire in February 2025. Under the PSC, the oil-and-gas-exploration company has contractual obligations to drill two more wells -Titly in block SS-04 and Moitree in block SS-09. But the OVL management has yet to engage any contractor for the drilling of Titly and Moitree wells, they said. With only one year left from its PSC tenure, the Indian firm is not likely be able to complete drilling in the given time, said sources. The firm has a budget of US$65 million to drill the wells, they said. Previously, Petrobangla had extended OVL’s PSC tenure until February 2025 from February 2023 at the latter’s request, as it ‘failed’ to carry out the necessary exploration works within its previous stipulated timeframe. It was the third extra period of time that the OVL got from the Bangladesh Oil, Gas and Mineral Corporation or Petrobangla. The state corporation earlier had extended the company’s PSC tenure by two more years until February 2023 from February 2021 in its bid to boost offshore exploration. Meanwhile, Petrobangla signed two PSCs with OVL, the operator of shallow sea (SS) offshore blocks SS-04 and SS-09, on February 17, 2014 which was set to expire in February 2019 as per terms of the original PSC. At Kanchan gas well, OVL had drilled beyond its targeted depth of around 4,228 metres in search of a commercially viable gas deposit. But all its efforts ended up finding only huge deposits of clay and shell-stone sequence and no sandstone, meaning there is no gas-reserve prospect there. The Kanchan well was up for the first offshore drilling in the country’s maritime territory in last six years. Australian company Santos along with Bangladesh Petroleum Exploration and Production Company Ltd (BAPEX) in February 2017 drilled Magnama-02 well under block 16 only to find it dry. The joint venture drilled the offshore well into a depth of around 3,200 metres, which cost BAPEX an estimated $29 million. The country has no producing offshore gas well, and its entire natural gas output comes from onshore fields as well as import of liquefied natural gas (LNG). OVL is the operator of blocks SS-04 and SS-09, having a participating stake of 45 per cent. Block SS-04 covers an area of 7,269 square kilometres (sq-km), while block SS-09 stretches over an area of 7,026 sq-km. Water depth of both the blocks ranges between 20 metres and 200 metres. As per the PSC, the firm is committed to conducting 2,700 line-kilometre 2D seismic-data acquisition and processing as well as drilling one exploratory well in block SS-04. Also, it has to do the same for another 2,700 line-km 2D seismic- data acquisition and processing as well as drill two exploratory wells in block SS-09. The OVL owners will be allowed to operate and sell oil and gas for 20 years from an oil-field and 25 years from a gas-field under the deals. The company has already completed around 3,100 line-km 2D seismic survey for both the blocks.
Russia’s Disrupted Oil Trade Crimps Margins for Indian Refiners
India’s state-run refiners are facing a shift in fortunes as once cheap Russian oil becomes more expensive and less accessible, squeezing profits for companies that had been benefiting from Moscow’s war in Ukraine Attacks in the Red Sea have driven up freight rates, while tougher US sanctions have stranded some Russian cargoes destined for India, adding to costs. That may force some processors to buy more pricey barrels from suppliers in the Middle East, eroding profit margins even more, say traders and analysts. India has to import 88% of its crude needs and the nation took advantage of cheaper Russian oil following the war in Ukraine as others shunned Moscow’s barrels. But the trade, which has helped put the state-owned refiners on track for a rebound in net income this year, is under pressure. Gross refining margins for processors including Indian Oil Corp. dropped in the previous quarter due to higher freight rates, said Hardik Shah, director at credit ratings and analytics firm CareEdge Group. The company estimates lower margins for refiners so far this financial year, but they are still higher than pre-war levels. The state-run processors primarily sell fuel domestically and don’t get the benefit of higher prices overseas, unlike the export-focused private processors including Reliance Industries Ltd. — which also have more flexibility on buying and payments for Russian crude. Indian Oil, Bharat Petroleum Corp. and Hindustan Petroleum Corp. didn’t immediately respond to emails seeking comment on margins. CareEdge predicts overall margins should hold around $10 a barrel, as long as crude prices stay below $90, a level that global benchmark Brent hasn’t been above since October. Futures traded near $83 on Thursday. The attacks on shipping in the Red Sea by Houthi rebels have also spilled into global fuel trade. Arrivals of fuel from India to Europe averaged just 18,000 barrels a day in the first two weeks of February, a plunge of more than 90% compared with January’s average, according to Vortexa Ltd. The disruptions will likely lead to some impact for Reliance and Nayara Energy Ltd., although they still have export options across Asia and Africa. Cheaper Russian oil has allowed India’s refiners to be more competitive than their peers in South Korea, Singapore and across the world. If India loses the Russian advantage on crude, whatever marginal refining edge it had will be gone, according to Mukesh Sahdev, the head of oil trading and downstream research at Rystad Energy.
India’s January crude imports hit 21-month high
India’s crude oil imports jumped to a 21-month high in January as the world’s third-biggest oil importer and consumer shipped in more fuel to meet surging demand led by strong industrial activity. Crude oil imports in January rose 9.5% month-on-month to 21.39 million metric tons, and were up 5.7% on a year-on-year basis, Petroleum Planning and Analysis Cell (PPAC) data showed on Thursday. India’s fuel consumption rose 8.2% year-on-year last month, government data showed earlier this month. India’s manufacturing industry improved substantially at the start of 2024, with factory activity expanding at its fastest pace in four months in January, while carmakers reported record sales last month. Imports of crude oil products rose 5% from a year earlier to 3.97 million tons in January, while product exports rose 7.5% to 4.84 million tons, data from the PPAC website showed.
LNG tankers may be converted to floating storage in India
A Japanese-Indian consortium is considering turning two LNG tankers into floating storage and regasification units to help meet growing demand in the South Asian economy, according to two people familiar with the matter. The units, with a capacity of 138,000 cubic meters each, are currently being leased by Petronet LNG Ltd. to import the super-chilled fuel from Qatar. Since the Indian company doesn’t plan to renew the lease past 2028, the consortium — called India LNG Transport Co. — may put the vessels to use on India’s east coast after retrofitting them in South Korea, said the people, who asked not to be named as they are not authorized to speak with the media A spokesperson for the Indian partner, state-owned Shipping Corp of India Ltd., didn’t reply to requests for comment. India is investing heavily in liquefied natural gas import infrastructure to help meet Prime Minister Narendra Modi’s target of gas reaching 15% of the energy mix by 2030, from less than 7% now. The South Asian nation, currently the world’s fourth-largest LNG buyer, could see its imports rise to 150 million tons by 2030, a seven-fold increase from 2023, Petronet’s Chief Executive Officer Akshay Kumar Singh said in February.
Upstream E&P companies shifting focus to longer contracts with lengthy lead times: Transocean
Oil and gas exploration and production (E&P) companies are increasingly directing their attention towards securing longer-term offshore deepwater contracts, accompanied by extended lead times until the commencement of these contracts, according to top executives at Transocean, a leading deepwater drilling company. According to S&P Global Commodity Insights, the executives made these remarks on February 20 during Transocean’s fourth-quarter earnings conference call, highlighting a shift in contracting dynamics within the industry. Despite experiencing a robust year of contracting activities in 2023, Transocean CEO Jeremy Thigpen acknowledged concerns among investors regarding a recent slowdown in the pace of contracting awards. Thigpen emphasized that the transition towards longer contract durations and lead times reflects the confidence of upstream operators in the longevity of the current upcycle and their commitment to the offshore market. He expressed optimism about the demand for Transocean’s assets and services, citing the encouraging trends in current and future rig demand. Thigpen said, “The extended duration [of contracts], with longer lead times to contract commencement… tends to result in prolonged contract negotiations. It also demonstrates our customers’ confidence in the longevity of this upcycle and their commitment to the offshore market. We remain extremely encouraged about the current and future demand for Transocean’s assets and services.” As an illustration of this trend, Thigpen provided insights into the average contract durations for Transocean’s drillships and semisubmersibles. In 2023, the average contract duration for drillships stood at 569 days, compared to 353 days in 2022 and 231 days in 2019. Similarly, semisubmersibles recorded an average contract duration of 404 days in 2023, up from 326 days in 2022 and 241 days in 2019. “Most of the negotiations taking place right now are for longer-term contracts, and thats where you can really start to… generate a lot of cash,” said Thigpen. This shift towards longer-term contracts signifies a strategic move by E&P companies to generate sustained cash flows and enhance operational stability. Moreover, the lead times between contract signings and start dates have also extended over the past couple of years, reflecting operators’ optimism about long-term commodity prices and the duration of the current upcycle. In 2023, drillship contracts were signed an average of 319 days ahead of their start dates, while semisubmersible contracts were signed 284 days in advance, compared to shorter lead times in previous years.
Cairn to double annual capital expenditure to $1 billion for 5 years
Cairn Oil & Gas will spend about $1 billion in capital expenditure (capex) annually for the next five years as it ramps up exploration activities across 12 key project areas. This will be double the $500 million worth of capex incurred annually by the company in the past couple of years, company officials told Business Standard during an interaction at the recently concluded India Energy Week. The announcement comes at a time when public-sector oil and gas producer ONGC and Oil India have outlined major exploration plans beginning 2024. “For the past three-four years, we have been spending at least $500 million .
Work on offshore breakwater at Dabhol LNG moves ahead
This 2.3 km long structure aims to reduce the action of the swell on the unloading vessels alongside. Concrete Layer Innovations (CLI) has been working with the contractor to assist with the manufacture, reuse and installation of the 9 and 12 m3 ACCROPODE™ I blocks that cover the armor of the structure. “The design of the structure implies a complete construction by maritime means on barges. The connection with the 500 m long existing breakwater is also one of the technical challenges,” Concrete Layer Innovations (CLI) said. The site is located at Anjanwel village, Dabhol port of Ratnagiri district of Maharashtra in India, about 340 km south of Mumbai.
India exported USD 6.65 billion oil products derived from Russian oil to sanctioning nations
Over one-third of India’s export of oil products to the G7-led coalition countries were derived from Russian crude, a European think-tank said, highlighting how the partners shunned buying Russian crude and imposed price caps but a loose policy on refined products allowed third countries to use Russian oil and legally export products to them. While there are no restrictions or sanctions on buying/using Russian crude oil and exporting fuels such as diesel derived from it, the Group of Seven (G7) rich nations, the European Union and Australia – called the price cap coalition countries – first set a crude price cap of USD 60 per barrel starting December 5, 2022, and later on products like diesel to keep the market supplied while limiting Moscow’s revenue. his was aimed at punishing Russia for its February 2022 invasion of Ukraine by depriving it of oil revenues while averting a surge in prices that could occur if Russian oil stopped flowing to global markets. “In the 13 months since the oil price cap took effect (in December 2022), over one-third of India’s exports of oil products to sanctioning countries was derived from Russian crude (EUR 6.16 billion or USD 6.65 billion),” the Finland-based Centre for Research on Energy and Clean Air (CREA) said in a report. “A huge proportion of these exports came from the Jamnagar refinery,” it said, alluding to the refinery operated by Reliance Industries Ltd in Gujarat. Jamnagar alone exported EUR 5.2 billion of oil products produced from Russian crude to the price cap coalition, it added. An email was sent to Reliance for comments to remain answered. “India imported Russian crude worth EUR 3.04 billion to create these products for sanctioning countries,” CREA said. The USA imported EUR 1.2 billion of oil products from India, which were estimated as being refined from Russian crude. “India imported EUR 733 million of Russian crude to create these products for the USA.” The price cap coalition countries imported a further EUR 469 million worth of oil products from the Vadinar refinery, it said, alluding to the refinery operated by Nayara Energy in Gujarat. “Russian energy giant Rosneft – who are on OFAC’s list of sanctioned entities – is its single largest shareholder with a 49.1 per cent share in the company.” The USA imported EUR 59 million of oil products from Vadinar starting from the introduction of the crude oil price cap until the end of December 2023. According to CREA’s estimate, 42 per cent of the refinery’s feedstock is Russian crude. While some Western nations have since February 2022 shunned buying Russian oil directly, they however import petroleum products from China, India and Turkey that have emerged as major buyers of Russian crude oil. Turkey’s port of Aliaga (the location of the STAR refinery and Tupras Aliaga Izmir refinery), was the second-highest exporting location of oil products made from Russian crude to the price cap coalition, it said. “EUR 8.5 billion (USD 9.18 billion) of price cap coalition countries’ imports of oil products between December 1, 2022 and December 2023 were made from Russian crude. These imports in 13 months are equivalent to 68 per cent of the EU’s annual commitment to aid Ukraine between 2024 and the end of 2027,” CREA said.