Traders Cut Bullish Bets on Oil Ahead of OPEC+ Meeting
Hedge funds and other institutional traders have reduced their bullish position on oil substantially ahead of the OPEC+ meeting on Thursday. In the week to November 21, bullish bets were slashed – with net-long positions being cut by over 19,000 positions to the lowest since June, Bloomberg reported, citing data from ICE Futures Europe and the CFTC. Long-only positions, meanwhile, also dropped by nearly 19,500 to the lowest since April. OPEC+ is meeting on Thursday to discuss production policies. News of internal disagreements added volatility to oil prices last week, while the possibility for deeper cuts from Saudi Arabia lent upward potential to benchmarks. Even with the potential of deeper cuts, oil began the week with a decline, extending a series of daily losses that began last week. Earlier today, however, the mood changed and both Brent crude and West Texas Intermediate began to trade with gains. Analysts attributed these to the nearing OPEC+ meeting and the predictions of deeper cuts. “Oil bears should be careful not to underestimate Saudi’s resolve,” Vishnu Varathan, Asia head of economics and strategy at Mizuho Bank, told Bloomberg. “But it will be hard for them to secure buy-in from all member states.” Last week, African members of the cartel were reported to have asked for higher production quotas despite Saudi Arabia’s attempts to keep a cap on production to keep prices higher. The latest reports suggest disagreements have been ironed out, after OPEC announced a postponement of the meeting, originally planned for last Sunday. This should help the group agree on net steps that, according to Eurasia Group analysts, could include additional cuts of up to 1 million bpd on top of Saudi Arabia’s voluntary cuts of the same size. In the absence of additional cuts, the Eurasia Group team said, Brent crude could drop to the low $70s, Bloomberg reported. This forecast suggests worries about economic growth have remained enduring despite factual data about oil demand so far this year.
New Reactor Design Is A Gamechanger For Green Hydrogen
The total market potential of hydrogen technology could reach $11 trillion by 2050, with major advancements and falling production costs, says Bank of America, which firmly believes “we are reaching the point of harnessing the element that comprises 90% of the universe, effectively and economically”. This year, in particular, has seen major momentum … Germany and Norway have agreed to build a hydrogen pipeline as a replacement for Russian natural gas and coal. Australia’s hydrogen project pipeline is one of the biggest in the world, with 12 million tons per annum–the bulk of which is green, or clean, hydrogen, according to Wood Mackenzie. In the U.S., McKinsey sees potential for the Gulf Coast–led by Houston–to become the world’s leading clean-hydrogen hub by 2030. Hydrogen could be far bigger than LNG, even. Texas alone, could see demand for hydrogen top 21 million tons per annum by 2050. “The effect would be significant: a clean-hydrogen hub could possibly generate around $100 billion in additional GDP by 2050 for Texas,” McKinsey says. Washington is also pouring money into hydrogen projects. The catalysts are lining up with phenomenal momentum, and there is a logical reason for this: Of all our climate change efforts, JP Morgan says hydrogen will be the “pivotal” source of energy over the coming decades, with both nuclear fusion and carbon capture, utilization and storage (CCUS) “unlikely to have a significant impact prior to 2030. Now, with all eyes on the real innovators here, a high-tech hydrogen breakthrough by privately-held GH Power opens another door in this burgeoning $ 11 trillion industry that’s created a hydrogen bull market. Reactor Hydrogen for North America North America is desperate for hydrogen breakthroughs, and GH Power’s new renewable energy technology is one of the latest. The technology uses exothermic reactions with only two inputs (end of life or recycled aluminum and water) to create three extremely valuable green outputs: hydrogen, alumina (aluminum oxide), and exothermic heat. The process uses recycled scrap aluminum as the key input. That aluminum is then mixed with water through a proprietary reactor designed to continuously operate to produce hydrogen, alumina, and exothermic heat (power) with zero emissions, zero carbon, and zero waste. That earns it a Carbon Intensity Score of -39 ( Based upon 3rd Party Report). The reactors are scalable and modular, which means they can be designed and built for small or scalable large power requirements with last-mile delivery. This advanced technology is simple to permit, build, operate and integrate with other industrial processes, even in remote areas. The reactor plant’s environmental footprint is extremely light: Each plant can fit up to 27 megawatts of green energy into a space that occupies only 2,000 square meters. GH Power is planning to develop a plant which produces 11,700 Tonnes of green hydrogen per year to fuel a 30-MW combined cycle plant with a net output of 27 MW. Led by world-class engineers with over 100 years of combined experience operating power plants, refineries, and other energy infrastructure, GH Power’s 2MW demonstration commercial reactor will start generating revenues in the second quarter of next year, and this is only the beginning. GH Power has a pipeline with blue-chip strategic partners to build out large-scale hydrogen power plants in North America and Europe. Its technology has won it global recognition, with a green technology grant in partnership with Germany’s RWTH Aachen University, sponsored by the Canadian and German governments. Finally, Low-Cost Hydrogen GH Power’s reactor is self-sustaining, zero emission, and is a net producer of energy for consumption. Most importantly, it’s a North American first: It’s cost-competitive with conventional fossil fuels. And the reactor’s value extends far further than this … It process also produces green hydrogen, exothermic heat, and green alumina, which has numerous commercial applications used for everything from lithium-ion batteries and LED lighting to semiconductor production. Green hydrogen produced from electrolysis costs about 3X more than hydrogen produced from natural gas, with the U.S. Department of Energy averaging green hydrogen at about $5 per kilogram. The enormous amount of money pouring into green hydrogen right now is intended to bring the cost down by 80% to $1 per kilogram within 10 years. So not only does GH Power say its reactor is already 60% cheaper than producing hydrogen by the currently most common method of electrolysis, but it’s also producing two other valuable green outputs for the market: exothermic heat that can be put back on the grid, and green alumina. The green alumina output is produced 85% cheaper than existing production processes of hydrochloric acid leaching and hydrolysis. GH Power’s technology is producing green hydrogen for 60% less than the current dominating process, thanks to its proprietary technology, which relies on only two inputs, water, and recycled aluminum, which is widely available everywhere for as little as $1.50/kg. GH Power’s reactor also produces green alumina for 85% less, it’s also going to play a role in decarbonization. The 27MW plant could produce 1.2 million tonnes of carbon offset every year. That’s a huge amount of carbon offset revenue potential considering that 1 metric ton of carbon offset costs between $40 and $80. Flipping The Switch On The First Reactor Phase 1 testing at GH Power’s first reactor in Hamilton, Ontario, has been completed, and Phase 2 testing was launched in late June. Phase 2 testing is preparation for commercial operations, which expect to be generating revenues by the second quarter of next year. Phase 3 moves to continuous operations of the 2MW reactor and integration into the final modular reactor design for a large-scale solution. The faces behind this green hydrogen breakthrough are major forces in the energy industry, led by CEO Dave White, a veteran engineer, and Chief Engineer Ken Stewart who has designed and managed thermal power plant and petrochemical processes across North America. COO Gary Grahn also has 25 years of international energy experience including in oil, gas, minerals, metals and utilities, CFO Anand Patel contributes a decade of real asset capital
IOC corners more than a third of D6 gas in latest Reliance auction
State-owned Indian Oil Corporation (IOC) has cornered more than a third of natural gas that Reliance Industries Ltd and its partner bp of the UK offered in the latest auction of the KG-D6 gas, sources said. IOC got 1.45 million standard cubic meters per day out of the 4 mmscmd of gas auctioned last week. The oil refining and marketing company, which was the top bidder even in the previous two auctions of gas from the eastern offshore KG-D6 block of Reliance-bp, bid the volumes as an aggregator on behalf of fertilizer plants. City gas companies including Torrent Gas and Gujarat Gas secured a total of 2.21 mmscmd of gas for turning into CNG for sale to automobiles and piped to household kitchens for cooking purposes, two sources with direct knowledge of the matter said. Gujarat Gas won the tender to buy 0.5 mmscmd, Torrent Gas 0.45 mmscmd, Adani Total Gas Ltd 0.29 mmscmd, IndianOil-Adani Gas Pvt Ltd 0.17 mmscmd and Indraprastha Gas Ltd and Mahanagar Gas Ltd 0.30 mmscmd each, they said. The auction saw participation from across the gas consuming sectors – fertilizer, city gas distribution, refineries and aggregators. A total of 38 successful bidders secured gas through the auction process, which concluded on November 24, they added. Reliance and bp last week auctioned 4 mmscmd of gas from the Krishna Godavari basin block starting December 1, 2023. They asked users to quote a price indexed to Brent crude oil price, according to the tender document. This was a departure from the previous two previous auctions, the last being in May this year, where gas was sold indexed to international gas benchmark, JKM. In the latest auction, Reliance-bp asked bidders to quote a premium ‘v’ they are willing to pay over and above 12.67 per cent of dated Brent crude oil price. The starting bid price for ‘v’ has been kept at USD 1.08 per million British thermal unit. Sources said the value of ‘v’ in the auction came to USD 1.98 per mmBtu. At the current Brent crude oil price of USD 80 per barrel, the gas price comes to USD 12.11 per mmBtu (USD 10.136 per mmBtu plus ‘v’ of USD 1.98). But the bidders will have to pay a lesser price as according to the tender document the sale price would be the lower of the government-dictated maximum rate payable for gas from difficult fields like deepsea, and the price arrived through the bidding process. The ceiling price payable for gas from difficult fields for a six month period starting October 1 is USD 9.96 per mmBtu. This means that even if Reliance-bp finds buyers for 4 mmscmd of gas are willing to pay USD 12.11 per mmBtu, the users will have to pay only USD 9.96 till March 31, 2024. The government bi-annually fixed ceiling price for gas produced from difficult fields such as deepsea and high-pressure, high-temperature (HPHT) fields, effective from April 1 and October 1. Natural gas, a cleaner-burning, efficient fuel, is being seen as a transition fuel for nations to move from polluting hydrocarbons to zero-emission fuels. In the last auction in May, IOC, the nation’s largest oil firm, had walked away with half of the 5 mmscmd of gas Reliance-bp had offered. In that auction, Reliance-bp had asked users to quote a variable ‘v’ over and above the JKM price, the spot market benchmark for liquefied natural gas (LNG) delivered to Japan and South Korea. At the end of that e-auction, gas was sold to 16 buyers at a price of JKM + (plus) USD 0.75 per mmBtu for 3 years. At the prevailing JKM price of USD 9.2 per mmBtu, the price for KG-D6 gas came to around USD 10. Reliance-bp had in April 2023 sold 6 mmscmd of gas. In that auction too, the final bid price came at USD 0.75 per mmBtu premium over the JKM price (JKM + USD 0.75 per mmBtu). The duo had a couple of years back used Dated Brent as the benchmark to sell KG-D6 gas before switching to JKM when international gas prices soared starting 2021. Gas produced from wells drilled below the seabed is used to produce electricity, make fertiliser, or turned into CNG for powering automobiles or piped to household kitchens for cooking as well as in industries. Reliance-bp produces about 29-30 mmscmd of gas from three sets of gas fields in the KG-D6 block.
Does the Natural Gas Industry Have a Future?
The natural gas industry’s domestic sales pattern over the past two decades makes one wonder whether the industry has much of a future. Okay, sales volume has gone up, at a slow pace, but most of that growth is due to increasing sales to wholesale electric power generators. The rest of the market has shown barely any growth. Table 1 shows annual rates of growth for major customer classifications as well as an estimate of the growth in propane usage. The table calculates growth using both compound annual and average annual growth rates. Either way, the numbers are dreadful. But not out of line with other energy growth rates, generally above the rate of population growth and below the rate of real economic growth. What does the future look like? Warmer winter weather means lower sales. So do more efficient appliances. And so do more efficient competitive products that use electricity like heat pumps. The Energy Information Administration projects that growth in overall demand will hover just below zero, although slightly higher for industrial use and lower for electric generation. Could be worse. What does the stock market think of that grim outlook? Presumably, investors have priced gas utility stocks as potential losers, selling at low ratios of price to earnings and paying ultra-high dividends, because they want immediate returns before the growth fizzles and the companies disappear. But not so. These stocks sell in line with what one might expect for reasonably safe, slow-growth utilities, not companies in terminal decline. What did the company’s senior management tell investors to convince them to take an optimistic view? The companies have a simple strategy. They invest in rate base, having convinced regulators that—like a perpetual motion machine—they must continuously spend money on plant expansion and on refurbishing of the network and strengthening connections to pipelines. A larger rate base requires higher earnings to cover costs, including cost of capital. The old regulated utility game is fairly straightforward. Expand rate base (i.e. assets) in order to grow earnings. As an aside, this is the same policy adopted by electric companies a few years ago, when they could anticipate little growth but they spent money on capital expansion anyway and got away with it. The difference, however, is that electric companies can now look forward to acceleration in demand, but gas companies cannot. Our question, then, is how long can gas utility managers continue with this strategy of making consumers pay more for a commodity when they keep using less of it? Especially when the sale of the product produces carbon dioxide which governments are attempting to limit. That does not sound like a sustainable business model to rational people, so why invest more money in such an industry? Okay, but consider this. Gas industry executives claim in response that their customers typically save $1000 per year over the alternatives. That’s not much of a sales pitch at a time when both residential and major business customers will pay more to get low carbon or no carbon alternatives, whether to be virtuous or to satisfy corporate “green” initiatives. What sensible marketer promises a low price for an inferior product? Now, technical developments offer the possibility of a cleaner (non carbon emitting) product. Renewable natural gas (from agricultural and municipal waste) could provide about 15% of end user needs. Hydrogen injected into the network might displace. another 15%. And gas derived from municipal wastewater treatment could displace another 15% of natural gas consumption. But here is the message for the gas distributors. The municipal wastewater plants will likely sell directly to generators of electricity, not inject the gas into the networks. The 30% reduction in total natural gas usage (through use of renewable gas and hydrogen) translates to a 40-50% replacement of natural gas within the networks of the distributors, the companies we are talking about, some of which, by the way, are making significant investments in renewable gas producers, opening up another avenue of growth for their stockholders. It means that gas companies could sell carbon-free gas to a large part of their customer base. That gives the companies time to figure out how to replace the rest of its gas supply, if possible. The smart companies are already telling shareholders that their networks can carry anything. So, to answer our opening question, the domestic gas industry does have a future, we think, at least over the medium term, despite stagnant sales, as long as it takes advantage of an opportunity to transform itself from a purveyor of carbon dioxide emitting products into a smart marketer of something else that’s cleaner and greener.
Regulator adds Mizoram to the bidding round
Oil regulator PNGRB has added Mizoram to the areas it has offered for bidding for a licence to retail CNG and piped cooking gas in the latest city gas bid round. In a notice, the Petroleum and Natural Gas Regulatory Board (PNGRB) said in continuation of the bids invited on October 13 for the development of the city gas distribution network for seven geographical areas, electronic bids are invited for the same in the state of Mizoram. Last date of bidding is February 23, it said.
India mandates biogas blending in CNG, piped gas
India plans mandatory blending of compressed biogas (CBG) in domestic compressed natural gas (CNG) and piped natural gas (PNG) to cut its reliance on expensive imports of LNG. Blending will initially be voluntary at 1pc for automobiles and households from the April 2024-March 2025 fiscal year and become mandatory from 2025-26, the oil ministry said on 24 November. Natural gas is mostly used in India’s gas distribution network through PNG in households and CNG for automobiles. The CBG blending obligation (CBO) will promote production and consumption of CBG in the country, oil and gas minister Hardeep Singh Puri said, adding that it will encourage investment of around 375bn rupees ($4.5bn) and help to establish 750 CBG projects by 2028-29. The CBO is to increase to 3pc during 2026-27 and to 4pc during 2027-28, after which it will rise to 5pc. A central repository body will monitor and implement the blending mandate based on operational guidelines approved by the oil minister. The government last month launched its 12th city gas distribution bidding round offering areas in Jammu and Kashmir, Ladakh, Arunachal Pradesh, Meghalaya, Manipur, Nagaland and Sikkim states to connect to the natural gas pipeline network. “At present about 23,500km-long gas pipeline network is under operation in the country and around 12,000km pipeline is approved/under construction,” Puri had said. India had 300 city gas distribution networks under the Petroleum and Natural Gas Regulatory Board as of August, covering 88pc of the country’s geographical area and 98pc of the population. The country has outlined plans to make India a gas-based economy, with the share of natural gas in its primary energy mix targeted to rise to 15pc by 2030 from around 6pc in 2022. The government also aims to have 1pc sustainable aviation fuel (SAF) in jet fuel by 2027, which will double to 2pc in 2028, it said on 24 November. This would be done initially for international flights, as part of the country’s effort to achieve net zero by 2070. Delhi initially targeted to have 1pc SAF blending in jet fuel by 2025, saying it would need 140mn litres/yr.
TAPI project gets special concessions
The caretaker government of Pakistan is said to have exempted Turkmenistan Afghanistan-Pakistan-India (TAPI) Gas Pipeline project from the Open Access Regime, OGRA Gas (Third Party Access) Rules 2018 and the Pakistan Gas Network Code, besides standard waiver of immunity in line with international precedents to be included in the Host Government Agreement (HGA), sources close to Secretary Petroleum told Business Recorder. These special concessions were approved by the Cabinet Committee on Energy (CCoE) headed by caretaker Minister for Power and Petroleum, Muhammad Ali last week of last month but its minutes were approved by the caretaker Minister three weeks after the meeting by incorporating desired changes. Sharing the details, sources said, Petroleum Division briefed the CCoE about the TAPI project. It was stated that TAPI Gas Pipeline project was aimed to bring natural gas from the Galkynysh and adjacent gas fields in Turkmenistan to Afghanistan, Pakistan and India. In order to strengthen the common understanding made by the TAPI parties and further to implement the project, Inter-Governmental Agreement (IGA) and Gas pipeline Framework Agreement (GPFA) were signed on December 11, 2010. The GPFA had provided certain protections and facilitation to the project company for the execution, implementation and operation of the pipeline for the life of the project. Moreover, given that TAPI was a trans-national pipeline project, Government of Pakistan (GoP) had agreed, under the GPFA, to adopt and implement uniform legal and regulatory framework for the project. As per the GPFA, Afghanistan and Pakistan are required to execute Host Government Agreements (HGA) with TAPI pipeline company Limited (TPCL), the project company. The Heads of Terms of the Host Government Agreement were signed between the GoP and TPCL on March 12, 2019.