Red Sea Crisis Adds 100,000 Bpd to Global Oil Demand
The threat of attacks by Yemeni Houthis on vessels crossing the Red Sea have added 100,000 bpd to global oil demand as ships choose to divert to a longer route around Africa. This is according to the chief executive of commodity trading major Vitol, Russel Hardy, who said that “We have had to re-orientate so much all over,” because of the crisis. Speaking at a panel at CERAWeek, as quoted by Reuters, Hardy noted that because of the situation in the Red Sea, the total distance traveled by ships now is about 3% more than it was before the Houthis began to attack vessels in the Red Sea. Analysts have been warning that the diversion of ship traffic from the Suez Canal to the Cape of Good Hope would tighten oil markers as it adds more than a week to the average journey between Asia and Europe. Earlier this year, one unnamed expert told Reuters that the rerouting had increased demand for oil by 200,000 barrels daily. This was also one reason why the International Energy Agency revised its oil demand outlook higher in its latest Oil Market Report. Calling the development “unexpected”, the IEA wrote that demand for oil was seen rising 1.7 million bpd in the first quarter of the year, “on an improved outlook for the United States and increased bunkering.” The oil market generally dismissed the effect that the situation in the Red Sea was having on oil demand, focusing on OPEC’s spare capacity, boosted recently by collective output cuts. However, the mood is beginning to change as the cuts get extended and Russian supply gets squeezed from Ukrainian drone attacks on refineries. With threats to supply elsewhere, the additional demand that the Red Sea situation may attract more attention and possibly serve to help oil climb higher still as there seems to be no resolution to it in sight for the time being.
Three-Year Low in LNG Price Prompts Asia Buying Spree
A substantial decline in LNG prices has led to an increase in purchases on the spot market from Asian buyers, such as China, India, and Southeast Asian nations. According to analysts cited by Reuters, this 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%, Reuters reported. This increase is quite understandable when one looks at prices. The average price per million British thermal units of LNG this quarter stood at $9.82. A year ago, the average price was a whopping $18.75 per mmBtu. “We’ve seen some buy tenders coming in more frequently given lower Asian LNG prices, especially from price-sensitive buyers like India, Vietnam and China,” Kpler LNG analyst Ryhana Rasidi told Reuters. “For this year, we believe that the increasing spot demand will contribute to raising overall Asian LNG demand.” The price decline came after a milder than expected winter in some parts of the northern hemisphere, which left more gas in storage. The continued growth in supply, especially in the United States, also helped drive prices down. This year things may change as U.S. natural gas producers begin to scale back production in response to low domestic gas prices. LNG demand is seen continuing on a growth trajectory, wherever prices go. Last month, a TotalEnergies executive forecast that this year, China and Europe will be the biggest drivers of LNG demand. Shell also expects China to lead the demand growth trend in LNG, where the supermajor sees a 50% increase in demand over the years to 2040.
Saudi Aramco To Expand Natural Gas Output Capacity by 60%
After scrapping oil capacity expansion plans earlier this year, Saudi state oil giant Aramco is now poised to boost natural gas output by 60% by 2030, Reuters reports, citing an Aramco executive on the sidelines of the Houston CERAWeek energy conference. In the third quarter of last year, Saudi Arabia made two significant natural gas discoveries in two fields in the Empty Quarter, along with the discovery of five reservoirs in previously discovered fields. At the Al-Hiran field, gas flowed at a rate of 30 million cubic feet daily. At the Al-Mahakik field, the gas flow was 0.85 million cubic feet daily. Demand for gas is seen increasing significantly amid a global energy transition, which has prompted Saudi Arabia to move more quickly to open up the development of unconventional natural gas fields. LNG demand is expected to grow by 50% by 2030. The Saudis’ growing interest in natural gas has also led to the Kingdom’s first acquisition in the LNG space earlier this year. Earlier this month, Reuters cited unnamed sources as saying that Aramco and Abu Dhabi National Oil Company (ADNOC) are in talks to invest in American LNG in order to compete with Qatar, which lost its ranking to the U.S. in January as the world’s largest LNG exporter. Aramco is reportedly in talks concerning the Sempra Infrastructure Port Arthur LNG Phase 2 project in Texas. Phase 1 is already producing, while Phase 2 has been proposed for expansion. The Saudi quest to expand its natural gas production capacity, along with its increasing interest in global LNG options, comes as the Biden Administration continues with a pause in approvals for new LNG projects imposed in January and adding uncertainty to new project financing for American LNG players.
Oman Takes The Lead in Green Hydrogen
Hydrogen produced with renewable power had a significant breakthrough this month, with the signing of an offtake agreement between a European buyer and an Indian producer in Oman. Yara, the Norwegian fertilizer and industrial chemicals producer, entered a long-term contract with ACME Cleantech Solutions Pvt. Ltd. to supply 100,000 tonnes per annum (mtpa) of ‘green’ ammonia beginning early 2027. ACME will soon start construction on a fully integrated plant on 12 sq. km in the Special Economic Zone at Duqm (SEZAD) on Oman’s central coast. It’s the first major agreement between non-affiliated companies for green ammonia and an important breakthrough for Oman. Anatomy of an agreement Ashwani Dudeja, Group President and Director, ACME Cleantech Solutions, says that the companies went through 20 months of negotiation. The agreement was signed just two weeks ago for a long-term contract of up to 30 years. Now, with the binding agreement in place, and financing arrangements with Indian lender REC Limited (Rural Electrification Corporation) finalized last year, the company is moving forward with the project’s first phase. Basic work at the site is underway and major work will begin this year. The Yara contract is for 100% offtake from phase 1. Production will occur at a fully integrated self-contained plant including electrolysis, hydrogen storage, ammonia production, and a flexible pipeline and jetty, which can load ammonia carrier ships directly from the plant. The production area encompasses 12 sq. km containing the solar power plant and a small wind plant to maintain EU Renewable Fuels of Non-Biological Origin (RFNBO) compliance, as Yara will take the volumes mostly to Europe. A land reservation agreement for 92 sq km was signed with SEZAD in 2022, with a usufruct agreement for the 12 sq. km phase 1. For this, the company worked with different ministries in the Omani government. Later, when the government’s new facilitating agency Hydrogen Oman (Hydrom) came into existence, ACME entered negotiations with Hydrom for a subsequent phase on the remaining 80 acres. The company intends to expand the project to 0.9 million tonnes per annum with approximately 3.5 GW of electrolyser capacity, to be powered by a 5.5 GWp solar PV plant. ACME is one of several companies operating in Oman with legacy project agreements now overseen by Hydrom. More projects in Duqm were announced in Hydrom’s Round 1 earlier this year. Hydrom is now conducting Round 2 for projects at Salalah on the south coast. A major concern is certification to meet evolving requirements for net-zero carbon hydrogen products. Early on, ACME retained testing and certifications services company TUV Rhineland to get the Oman project pre-certified based on plan. This has now expired and the company will seek new certification of the finished plant as per the prevailing standards. “This is an evolving area, there’s no unified standard globally at the moment for hydrogen or ammonia,” says Dudeja. “It’s big draw-back at the moment, the rules for certification in Europe may be different than in Asia, so which certification method to follow?” he says. “Negotiating what happens if there are changes becomes a tough exercise.” The company, with others, is advocating with regulatory bodies to create some kind of standardized certification methodology for project developers to follow. Seeking certification As carbon-free hydrogen moves closer to market, it’s clear that companies are now dealing with more than demand risk. They are trying to adapt to regulations at an early design phase, to comply with the European RFNBO requirements under RED II and III, which lay down the conditions that will make hydrogen products compliant. But these requirements for ‘green’ certification are evolving in different regions including Asia, adding complexity to project design and causing companies in Oman and elsewhere to proceed cautiously. Oman has set up a framework for a pre-certification exercise, to help developers seeking to reduce uncertainty. “The pre-certification work, to stress test what will be the certification, the degree of greenness of the molecules if we would export them to Europe, has been essential,” said Stefani Giuseppe, General Manager Green Hydrogen, DEME Concessions NV, speaking at the World Hydrogen MENA conference in Dubai last month. “It’s one of the pieces of the puzzle we need before investing further in the project,” he said. His company, partnered with Oman’s OQ Alternative Energy in the Hyport Duqm consortium, is among the multinational consortia that were awarded land blocks by Hydrom last year. Hyport Duqm plans to produce approximately 330,000 metric tons of green ammonia from a combined renewable power capacity of around 1.3 GW in a first phase. “It (certification) is a major challenge very much related to the off-take, which is essential,” said Giuseppe. First mover know-how Ashwani Dudeja came to ACME two years ago after nearly three decades in the gas, LNG and power business including stints at BG Group, Shell and ADNOC. He says that the company came to Oman with experience that gave it confidence to assume first-mover risk and have a head start. “With green ammonia, about 90% of the commodity price is capex, so everything is up front, so with an up front commitment on capex you need certainty of cash flows for the project finance to happen.” “We assumed a lot of risk,” he says. The 20 months of negotiation with Yara produced a contract that did not have much precedent. While most (grey) ammonia trades on short-term contracts, the green product required a long-term contract to match the project financing period. “It was a great learning for both organizations.” Another important part of the company’s learning came from its pilot plant, which it built at Bikaner in Rajasthan. It’s an integrated green hydrogen and ammonia plant, operating for two years now, producing 5 tonnes per day with power from a dedicated 5 MWp solar plant. This pilot, built at considerable cost, does not earn a commercial return; the product is sold on the market at grey ammonia prices. Yet it gave the company important knowledge. “We wanted to learn how to operate the electrolysers
StanChart: Oil Demand Set for All-Time High in May
Crude oil futures have rallied close to a five-month high with concerns about tightening supplies driving up prices in recent days, only coming down to earth on Wednesday and paring some of those gains while awaiting an interest rate signal from the U.S. Federal Reserve. According to StoneX energy analyst Alex Hodes, Ukraine’s recent attacks on Russian refineries could potentially cut ~350K bbl/day of global petroleum supplies and boost U.S. crude prices by $3/bbl. Analysts at J.P. Morgan estimates that 900K barrels of Russian refinery capacity have gone offline after the attacks, adding a risk premium of $4/bbl to oil prices. Brent futures have extended their year-to-date gain to nearly $10 per barrel (bbl) to trade at $85.93 at 1145 hrs ET in Wednesday’s session while WTI crude has gained 13.8% YTD to $81.66/bbl. Also supporting crude prices is stronger-than-expected demand with commodity analysts at Standard Chartered noting that energy markets kicked off the new year with an overly pessimistic view of oil demand. Following the release of the latest Joint Organisations Data Initiative (JODI) report on Monday, StanChart estimates that January demand clocked in at 100.24 million barrels per day (mb/d), good for a 2.67 mb/d year-over-year increase. That figure is 0.25 mb/d higher than StanChart’s latest forecast, a development that has prompted the analysts to revise their 2024 demand growth forecast to 1.69 mb/d from 1.64 mb/d previously. The analysts have also predicted we are going to see a sustained period of inventory draws in H1-2024, with the cumulative draw during the first half of the year coming in at 185 mb compared with a H1-2023 build of 230 mb. StanChart says demand indications remain robust, and have predicted that global demand will hit a new all-time high of 103.01 mb/d in May, a record which will be broken in June and again in August when demand is expected to clock in at 103.62 mb/d and 104.31 mb/d, respectively. StanChart has predicted that tightening oil markets will continue to power the oil price rally and has reiterated its long-held forecast for Brent to average $94/bbl in Q2-2024. Supply Constraints StanChart has predicted that oil markets will continue to be supply-constrained for the better part of the year. The analysts see limited growth for U.S. crude production, with U.S. supply not likely to move significantly higher than November 2023’s all-time high of 13.319 mb/d. Meanwhile, Russia will continue to struggle to optimize its upstream and downstream oil system, with logistical constraints due to war damage as well as a lack of critical spare parts contributing to a negative outlook for Russian crude and refined products output. More importantly, StanChart sees OPEC+ having ample room to maneuver starting in the third quarter. The analysts have pointed out that a 0.9 mb/d increase in OPEC output in the third quarter would still lead to an inventory draw of 0.5 mb/d for the quarter on top of the 1 mb/d draw across H1-2024. Indeed, OPEC has room to increase Q3 output by as much as 1.5 mb/d Q/Q without increasing inventories. The Energy Information Administration (EIA) is the most bearish of the leading energy agencies; however, using its model, OPEC could increase output by 0.8 mb/d Q/Q without triggering an inventory build. StanChart notes that Q3 crude balances are such that OPEC could significantly increase crude output without depressing prices or negatively affecting inventories. Unfortunately, the mid-term natural gas outlook remains bearish. The latest JODI oil and gas data release showed a modest recovery in European natural gas demand, with gas demand in France increasing 5.5% Y/Y in January; +4.1% in the UK, +4.3% in Italy and +13.2% in Spain. Germany was the main exception after recording a 3.6% Y/Y fall in demand. Still, Europe’s gas demand remains well below January 2022 levels, with demand in France 15.4% lower compared to levels two years ago; -9.9% in the UK, -9.7% in Germany, -19.4% in Italy and -20.2% in Spain. It’s highly unlikely that the situation will change soon with inventories already starting to build up in Germany and Italy before the withdrawal season is even over. The latest Gas Infrastructure Europe (GIE) data shows that EU inventories stood at 69.70 billion cubic meters (bcm) on 17 March, good for a 5.58 bcm Y/Y increase and 21.39bcm above the five-year average. That said, European gas prices have posted a strong rally despite record-high inventories, partly due to a reduction in LNG exports from the Freeport, Texas, terminal and also partly due to renewed market concerns about the supply security of the remaining flows of Russian gas into Europe. Front-month Dutch Title Transfer Facility (TTF) gas gained EUR 3.892 per megawatt hour (MWh) w/w to hit a one-month high of EUR 28.822/MWh on 18 March.
Two Tankers With Russian Crude Idle for Weeks Off India
Two tankers carrying Russian flagship Urals crude have been idling off the West Coast of India for more than three weeks without any indication of when they will unload. The Aframax tanker Crude Centurion arrived at the West Coast of India on Feb. 21, about 100 miles away from Sikka, its destination. Another, the Afragold, had been floating nearby since Feb. 29 after briefly signaling Mundra. Both loaded about 700,000 barrels of Urals from Russian Baltic sea port Primorsk in January. It remains unclear why they have been idling but there are growing signs that western sanctions are disrupting the fleet of tankers moving Russian oil. Tankers transporting the nation’s barrels have been doing strange things following a ramp up in US sanctions targeting traders and shipping companies moving the nation’s petroleum. Over the past few months, several tankers idled in the Indian Ocean for days before discharging in Indian ports or diverting to Middle East.
Higher domestic gas production to keep LNG imports range-bound for two years
India’s liquefied natural gas (LNG) imports are expected to remain range-bound for the next two years, beginning FY25, on account of growing production of natural gas in the country, ratings agency CareEdge said. India is envisaged to have a robust demand for natural gas from all the major consumption segments such as fertilisers, city gas distribution (CGD), power, refineries and petrochemicals. With imported gas prices normalising around $10-$12 per million British thermal units (mBtu) by FY23-end and remaining range bound in FY24, gas consumption has again started its upward trajectory in 9M FY24 and CareEdge Ratings expects India to record its highest-ever gas consumption annually in FY24. On the back of limited domestic natural gas production, India historically had a high dependence on imported gas. However, during the last three years ending FY23, gas imports declined mainly due to improved domestic gas production and a rise in imported gas prices. “Going forward, gas imports are expected to increase at a moderate pace in spite of expected growth in domestic production because consumption of natural gas is expected to outpace domestic production. Still, imports as a percentage of total consumption are expected to remain largely range-bound during the next two years, up to FY26,” CareEdge said. After hitting a high of 92 million standard cubic meters per day (MSCMD) in FY20, LNG imports declined consistently hitting 73 MSCMD in FY24. CareEdge expects imports to hit 82 MSCMD each in FY24 and FY25. It also projects inbound shipments to reach 96 MSCMD in FY26. With the rise in domestic natural gas production, India’s dependency on imported LNG, which stood at 53 per cent of total consumption in FY21, has gradually declined over the last three years and is expected to remain around 45 per cent by FY26.