UAE Slashes Exports of Medium Sour Crude
The United Arab Emirates (UAE) is slashing exports of its Upper Zakum grade as it is diverting more volumes of the medium sour crude to a huge domestic refinery, traders and analysts have told Reuters. ADNOC, the state oil and gas firm of one of OPEC’s top producers and exporters, is estimated to have shipped around 650,000 barrels per day (bpd) of Upper Zakum crude in March, compared to a monthly average of around 940,000 bpd throughout 2023, according to Rystad Energy data cited by Reuters. At the same time, ADNOC has exported more volumes of the lighter and sweeter grade Murban to replace lower volumes of Upper Zakum, according to traders and analysts. More Upper Zakum crude is now being run at ADNOC’s refurbished Ruwais refinery, which has a capacity to process 837,000 bpd of crude. Back in 2018, ADNOC said it would invest $3.1 billion to introduce crude processing flexibility at its Ruwais oil refinery. Since then, the refinery has been modified to enable ADNOC’s Ruwais Refinery-West complex to process up to 420,000 bpd of Upper Zakum crude or similar crude types. This has freed more volumes of the UAE’s Murban crude, which fetches a higher price on the global oil markets, to be utilized for export sales. Commenting on the refinery modification at the time, ADNOC said that “we can maximise the benefit of price differentials to enhance refinery margins, improve the middle distillate products and release valuable Murban crude into the market.” ADNOC began using Upper Zakum at its domestic refinery in September last year, traders told Reuters. Later in the autumn of 2023, sources familiar with ADNOC’s plans told Reuters that the Abu Dhabi firm had already notified some of its term customers that it would reduce the volume of Upper Zakum supply in 2024. On the other hand, the UAE has said it would boost supply of the more expensive Murban crude, especially as the Middle Eastern producer won a higher quota under the OPEC+ agreement for 2024. “Barrel-for-barrel, Murban brings more revenue for equal compliance,” Adi Imsirovic, director of Surrey Clean Energy, told Reuters. Importers of the UAE’s medium sour grade Upper Zakum, most of all China, will now have to scour the market for other sources of heavier crude.
Asia LNG Purchases Hit March Record
Imports of liquefied natural gas into Asia last month hit the highest ever for that month, at 24 million tons, which was a 12% increase on a year earlier, Bloomberg reported, citing Kpler data. The leaders of the importers’ pack were China, India, and Thailand, the data showed, with imports expected to continue at elevated levels as ample gas inventories are dampening demand for new shipments and lower prices on the spot market. Because of that lower demand, shipments of liquefied gas to Europe dropped 20% in March from a year earlier, Kpler also said. Within Asia, India led with the highest increase in LNG imports, at close to 20%, followed by China, whose LNG purchases increased by 22% in March from a year earlier. Japan’s LNG intake added 8%, after two months of import declines in a row, the data also showed. Weak European demand has helped push LNG prices lower, making the fuel more attractive for large Asian buyers. Three months before the March record, shipments of LNG to Asia hit the highest ever for any month: the December total stood at 26.61 million tons, again per Kpler data. High LNG import levels in China and the rest of Asia could create more competition for LNG supply to Europe at a later point as the continent is now more dependent on the super-chilled fuel for its natural gas supply after the loss of a large part of the Russian pipeline gas supply. The relative calmness in the LNG market in recent months could turn into volatile turbulence again if fresh supply concerns emerge and if this winter is really cold in Europe and/or Asia. These lower LNG prices on the spot market could see China break its own LNG import record, set back in 2021, and boost India’s intake of liquefied natural gas by 10% this year. In 2021, China imported 78.8 million tons of LNG. Asia LNG purchases on the spot market totaled 161 cargoes over the first three months of the year, S&P Global data shows, which was an annual increase of about 33%
Natural Gas Producers Are Ready To Pounce When Prices Rebound
U.S. natural gas producers are slashing production in response to multi-year low prices. But they are also looking beyond the current slump, preparing to turn on more output by flexible operation of their inventory of wells. “Natural gas is currently pricing at or below costs of production,” an executive at an exploration and production company said in comments in the quarterly Dallas Fed Energy Survey released this week. Prices are historically low due to weak winter demand amid milder weather, record output at the end of 2023, and higher-than-average natural gas stocks. Working natural gas stocks in the week to March 22 were 41% more than the five-year average and 23% higher than last year at this time, per the latest EIA data. The oversupply and low prices have prompted many producers to start reducing production. But some are also stocking up inventories of wells ready to start pumping – or to be turned in line – as soon as prices rebound. Producers expect natural gas prices to recover next year amid growing demand for LNG exports and new LNG export plants that are slated to begin operations in 2025. “All of us in the natural gas business are pinching as many pennies as we can right now,” Josh Viets, Executive Vice President and Chief Operating Officer at Chesapeake Energy, told the audience at Hart Energy’s DUG GAS+ Conference & Exhibition 2024 in Louisiana this week. But Chesapeake Energy, set to become the top U.S. natural gas producer after the planned merger with Southwestern Energy, is also deferring production from around 80 wells this year, which would give it up to 1.0 bcf/d of productive capacity available from deferred turn in line wells (TILs) by the end of 2024. “The way I like to think about it is we’re using the reservoir as storage,” Viets told the conference, as carried by Bloomberg. “When the market says, ‘hey, I need more gas,’ we’ll be in a position to quickly restore that to help meet the needs of consumers.” In the Q4 2023 earnings release in February, Chesapeake Energy said it would be building productive capacity to align with consumer demand. By year-end, the company plans to have deferred around 35 drilled but uncompleted wells (DUCs) and about 80 TILs. A measured approach to production activation would be responsive to market demand, Chesapeake noted. Other U.S. natural gas drillers, including the current top producer EQT Corporation, have also reduced output in response to the low domestic prices. “The low prices we are experiencing now are causing us to tuck it in and keep our powder dry,” an executive at an E&P company said in comments to the Dallas Energy Survey. “While companies are certainly protective of cash flow, they all want to be ready to service the next wave of LNG projects coming online in 2025,” Erin Faulkner at Enverus wrote this week. Despite multi-year low natural gas prices in the United States, domestic producers continue to be optimistic about the long-term prospects of gas as a fuel, both in America and abroad. Recent deals for LNG supply and midstream expansion point to an optimistic view in the industry about global gas demand and the role the U.S. could play in meeting said demand, despite the halt to LNG permit reviews. Chesapeake, for example, signed in February its first LNG Sale and Purchase Agreements to buy around 0.5 million tonnes per annum of LNG from Delfin LNG at a Henry Hub-linked price with a targeted contract start date in 2028. Chesapeake will then deliver the LNG to commodity trader Gunvor on an FOB basis with the sales price linked to the Japan Korea Marker (JKM) for a period of 20 years. Pipeline giant Enbridge announced this week a joint venture to build and operate natural gas pipelines connecting gas supply from the Permian to the U.S. Gulf Coast to tap into growing LNG export demand. Henry Hub prices are set to rise by the end of 2024, and further still in the medium term, according to executives polled in the Dallas Fed Energy Survey. Survey participants expect a Henry Hub natural gas price of $2.59 per million British thermal units (MMBtu) at year-end, compared to an average price of $1.44 per MMBtu through most of March when the survey responses were collected. Executives see Henry Hub prices at $3.18 per MMBtu two years from now, and at $3.94 per MMBtu five years from now.
US Oil Suppliers Muscling Into OPEC+ Markets All Over the World
One major beneficiary of sanctions on Russian and Venezuelan oil? US suppliers who’ve muscled their way into markets once dominated by OPEC and its allies. US oil exports have set five new monthly records since Western nations began imposing sanctions on Russia in 2022. And with trade restrictions on Venezuela set to renew in April, American barrels are beginning to displace sanctioned crude in India, one of the biggest buyers of illicit oil. The shift underscores the extent to which sanctions have helped American crude capture market share around the world. While US oil has long been the world’s go-to flex barrel, the disruption of energy flows after Russia’s invasion of Ukraine created new pull for American barrels. Shipments to Europe and Asia surged in the aftermath, transforming the US into one of the world’s largest exporters. Record production from the US — coming just as OPEC and its allies curb their own supply — has also helped American producers gain a bigger foothold in overseas markets. Physical oil prices are reflecting that, with WTI in Houston trading near the highest levels since October and sour benchmark Mars not far behind. “US production is going up and OPEC and Russian production is going down — so the US, by definition, is going to have more market share,” said Gary Ross, a veteran oil consultant turned hedge fund manager at Black Gold Investors LLC. India — the third-largest crude importer and Moscow’s second largest buyer after China — is the latest market seeing an influx of US oil. American shipments to India are set to jump in March to the highest in nearly a year, according to data from crude tracking firm Kpler. At the same time, Russian oil imports have fallen by about 800,000 barrels a day since last year’s high point, Bloomberg tanker tracking shows. Russian shipments may decline further with Indian oil refiners no longer accepting cargoes from tankers owned by state-run Sovcomflot PJSC, which was recently sanctioned by the US. While US supplies can’t fully replace Russian crude due to differences in oil quality and voyage times, “there’s definitely a bit of a pivot there towards pulling in more US crude,” said Matt Smith, lead Americas oil analyst at Kpler. Indian refiners have also halted purchases from Venezuela ahead of the expiry of a US sanctions waiver in the middle of next month. Those supplies are now poised to hit the lowest this year. Even before the latest raft of trade restrictions, the US was fast becoming a key supplier to Asia, where US imports hit an annual record last year, according to the EIA. And in Europe, which has largely eschewed Russian oil since the war in Ukraine began, US shipments will hit a record 2.2 million barrels a day in March, according to vessel tracking data compiled by Bloomberg. To be sure, not all of the pull from Europe is due to sanctions. Imports into the Netherlands have surged since West Texas Intermediate was included in the dated Brent benchmark last year, ensuring US crude would become a part of the European diet. But shipments increased markedly after the imposition of sanctions as European nations sought non-Russian sources of supply. US imports to France jumped nearly 40% from 2021 to 2023, while those to Spain rose 134%. “As US production continues to gradually grind higher, every incremental barrel that’s being produced is likely going to be exported,” said Kpler’s Smith.
Bangladesh Govt to procure 24 LNG cargoes from Gunvor Singapore as demand surges
Each cargo will contain 3.360 billion mmbtu (million British thermal units) LNG and the pricing will be determined based on the JKM (Japan Korea Marker) index. The Cabinet Committee on Economic Affairs on 27 March approved in principle the procurement proposal sent by the Energy Division on 13 March. Zanendra Nath Sarker, chairman of Bangladesh Oil, Gas and Mineral Corporation (Petrobangla), on 28 March told TBS, “This is the first time Bangladesh is importing LNG cargoes under a short-term contract. The company will deliver one cargo monthly, with the flexibility to adjust based on demand. “Most Importantly, the pricing will adhere to the JKM formula, with additional terms favourable to Bangladesh. This arrangement is anticipated to benefit Bangladesh significantly.” Energy Secretary Md Nurul Alam told TBS, “Gunvor Singapore’s proposal was approved by the Cabinet Committee on Economic Affairs at the latest meeting. Now, once the pricing is determined, it will be submitted to the Cabinet Committee on Government Purchases for final endorsement.” When asked about the price proposed by Gunvor, the energy secretary said, “Bangladesh has six long-term contracts with different companies for LNG purchase. We have a clear understanding of the market price. Besides, Gunvor Singapore will adhere to a formula [JKM], making the evaluation process straightforward.” Earlier on 10 January, the Singapore-based company proposed to the Energy Division to deliver 12 cargoes this year, and 12 cargoes in 2025. On 4 March, Prime Minister Sheikh Hasina, who is also the minister of Power, Energy, and Mineral Resources, approved the procurement proposal process. Currently, the government purchases spot LNG from 23 global companies, including Gunvor Singapore Ltd, through tendering and through long-term contracts from Qatar and Oman. On 23 January, the cabinet committee on government purchases authorised the procurement of an LNG cargo from Switzerland’s Total Energies Gas & Power Ltd at a rate of $10.88 per mmbtu. Another spot cargo from Gunvor Singapore Ltd is expected to arrive in April for which the government is paying $9.37 per mmbtu. Other than spot LNG, the Energy Division also procures LNG from Oman and Qatar via long-term contracts, which are processed and supplied to the national grid by the two LNG terminals set up at Maheshkhali in Cox’s Bazar. However, buying 24 cargoes from Gunvor Singapore marks the country’s first LNG procurement under a two-year contract. The Energy Division now seeks to procure LNG through short-term contracts rather than long-term ones, attributing this decision to the fluctuating nature of LNG prices in the international market, which complicates sourcing. A review of Petrobangla’s LNG procurement records from the spot market in recent years revealed fluctuating prices. In 2022, spot LNG was procured at rates ranging from $38.93 to $24.25 per mmbtu. In 2023, Petrobangla purchased LNG at prices ranging from $19.74 to $10.97 per mmbtu. As of January 2024, the highest recorded price for purchased LNG stood at $15.96 and the lowest price was recorded at $9.77 per mmbtu.
India accounts for 20% of upcoming regasification capacity in Asia Pacific
India, the world’s fourth largest liquefied natural gas (LNG) importer, is expanding its natural gas infrastructure by adding 24 million tonnes per annum (mtpa) of capacity accounting for around 20 per cent of the total regasification capacity being added in Asia Pacific. As per the latest annual report of the Gas Exporting Countries Forum (GCEF), India will be the world’s largest growth market for natural gas in the next decade with China claiming the top spot till 2030. The GECF report pointed out that Asia-Pacific boasted of around 566 MTPA of regasification capacity in 2022, with a significant 82 per cent primarily situated within the legacy JKT (Japan, South Korea, Chinese Taipei) group, constituting 64 per cent and China with 18 per cent. The rest, comprising South and Southeast Asia, contributed to the remaining 18 per cent. Among these, Japan leads with 210 mtpa , followed by South Korea (139 mtpa ), China (100 mtpa) and India (40 mtpa). “In 2022, construction was underway for approximately 121 mtpa of regasification capacity in Asia Pacific, with China (74 mtpa ) and India (24 mtpa ) taking the lead. China represents around 60 per cent of the capacity under construction, while India is responsible for roughly 20 per cent of the ongoing development of regasification infrastructure,” it added. Asia Pacific is projected to remain the dominant long-term LNG import market. “China is poised to be the largest growth market this decade, but India is expected to assume that role after 2030. South and Southeast Asia are forecast to be the markets with the highest incremental LNG import growth, albeit from a lower base,” the report anticipates. Expanded capacity India’s gas demand is forecast to be met via expanded gas pipeline and LNG regasification capacity. Estimations indicate that Indian LNG imports could double, reaching 39 mt by 2030, and rise to 80 mt by 2040 and 105 mt by 2050. “Realising such an outcome necessitates substantial investment in both supply and distribution infrastructure. By 2050, it is anticipated that India will increase its regasification capacity by 75 mtpa, reaching a total of 115 mtpa , which marks a significant rise from the existing capacity of 40 mtpa,” GECF said. India is actively targeting a 15 per cent increase in the share of natural gas in its energy mix by 2030. This goal is to be achieved through the expansion of pipeline networks, construction of LNG terminals, and support for domestic production. However, the GECF report said that despite a robust government ambition for natural gas to reach 15 per cent, the target is “unlikely to be met”. Gas production Natural gas production in India has been on an upward trajectory since 2020, surging from 24 billion cubic meters (bcm) to 35 bcm in 2023. A significant portion of this increase is attributed to offshore production, accounting for over 70 per cent of the overall production growth. Introduced in 2016, the Hydrocarbon Exploration and Licensing Policy (HELP) sought to enhance India’s upstream sector regulations, attract foreign investment and expedite exploration activities. This initiative introduced revenue-sharing contracts (RSC) as a replacement for conventional Production Sharing Contracts (PSCs). The shift aimed to streamline operations, address challenges such as cost recovery and stimulate increased exploration opportunities, ultimately enhancing the country’s upstream activities. These reforms have fostered greater international participation in India’s upstream sector. For instance, Reliance Industries (RIL) and BP, have brought three offshore fields into production since 2020. The R-series commenced production in 2020 followed by the Satellite Cluster in 2021 and most recently, the MJ field. BP estimates that, at their peak, these fields are to collectively produce 10 bcm to meet domestic demand in India, GECF noted. Oil and Natural Gas Corporation (ONGC) is planning to boost its natural gas production by 25 per cent by 2025 from 2022 level through intensified exploration. In recent developments, ONGC announced the discovery of a gas field in the Mumbai basin and an onshore discovery in the Krishna Godavari basin, it added. “We anticipate that India is expected to achieve a natural gas production level of 50 bcm by 2050, with 95 per cent of this production originating from offshore projects,” the report anticipates.
Govt reduces gas price for Reliance to $9.87; rate for CNG, PNG unchanged
The government on Sunday cut the price of natural gas produced from difficult areas like deep sea KG-D6 block of Reliance Industries, marginally to $9.87 per million British thermal unit in line with softening of benchmark international gas prices, an official notification said. However, the price of gas that is used for making CNG for fuelling automobiles or piping to household kitchens for cooking purposes will remain unchanged due to a price cap that is set at 30 per cent less than market rates such as that paid to Reliance. For the six-month period starting April 1, the price of gas from deepsea and high-pressure, high-temperature (HPTP) areas has been cut to $9.87 per mmBtu from $9.96, oil ministry’s Petroleum Planning and Analysis Cell (PPAC) said in a notification. This is the third straight bi-annual reduction in rates for difficult fields. Price was for six months beginning October 1, 2023 slashed 18 per cent to $9.96 per mmBtu from $12.12 for the April to September 2023 period. Prior to that, the rate was a record $12.46 for October 2022 to March 2023. The government bi-annually fixes prices of the locally-produced natural gas — which is converted into CNG for use in automobiles, piped to household kitchens for cooking and used to generate electricity and make fertilisers. Two different formulas govern rates paid for gas produced from legacy or old fields of national oil companies like Oil and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL), and for newer fields lying in difficult-to-tap areas, such as deepsea. Rates are fixed on April 1 and October 1 each year. In April last year, the formula governing legacy fields was changed and indexed to 10 per cent of the prevailing Brent crude oil price. The rate was, however, capped at $6.5 per mmBtu. Rates for legacy fields are now decided on a monthly basis. For April, the price came to $8.38 per mmBtu but because of the cap, the producers would get only $6.5 per mmBtu, the PPAC said. The price for difficult area gas continues to be governed by the old formula that takes a one-year average of international LNG prices and rates at some global gas hubs with a lag of one quarter. International prices had fallen in 2023 and so it will translate into lower prices for difficult fields starting October. India is aiming to become a gas-based economy with the share of natural gas in its primary energy mix targeted to rise to 15 per cent by 2030 from the existing level of around 6.3 per cent.