The disconnect in the Indian gas sector
nion Budget 2022 did not mention of any gas-related schemes or infrastructure — not even the city gas distribution (CGD) network — despite the recent conclusion of the 11th round of CGD bidding. Yet, state gas utility GAIL (India) announced pre-Budget that it had commenced India’s first-of-its-kind project of mixing hydrogen into the gas system in Indore, Madhya Pradesh. This hydrogen-blended gas — known as grey hydrogen — will be supplied to a joint venture for retailing of compressed natural gas (CNG) to automobiles and piped natural gas (PNG) to households for cooking. The pilot project is using ‘grey’ hydrogen with a view to subsequently use green hydrogen. Green hydrogen is the only clean form of hydrogen as it is produced without harmful greenhouse gas emissions by separating hydrogen from water using electrolysis with renewable energy. Grey hydrogen, on the other hand, is produced by separating hydrogen from the fossil fuel gas (which is one part carbon and four parts hydrogen). The details of GAIL’s proposed pilot have yet to be published, but proponents would need to be looking very closely at the investment risk of such a project due to recent global gas volatility and record high prices, making gas a very expensive resource. Rising prices Gas-using States such as Maharashtra, Gujarat and Delhi saw repeated upward revision in CNG and PNG prices last year, especially after the bi-annual October revision of gas well-head prices, which saw prices rise to 62 per cent for regular fields and 69 per cent for difficult fields. For instance, CNG and PNG prices were revised more than five times in 2021 by a gas utility in Mumbai leading to 34 per cent and 31 per cent increases, respectively. Indian spot LNG imports also increased last year, from $8.21/MMBtu (million metric British thermal unit) in January 2021 to $30.66/MMBtu in December 2021 — an increase of 270 per cent. The upcoming April 2022 revision in producer gas prices, to be calculated using the volume-weighted average price (VWAP) of four international benchmarks with data from January-December 2021, is expected to be much higher given recent peaks in international gas prices. It is being estimated that domestic gas prices from regular fields will double in April 2022 (from the $2.9/MMBtu increase in October 2021) to $6/MMBtu, and would further increase to $8/MMBtu in October 2022. This increase in producer gas prices would translate into increased prices for gas consumers in household, commercial and industrial sectors, making gas use extremely unaffordable, and dampening existing demand. Further increases in gas prices would also make the production of grey hydrogen, which needs to use this expensive gas, an infeasible proposition. The disconnect between government policy and GAIL’s pilot illustrates an uncertainty in India’s gas sector, which has been suffering from extreme price fluctuations having reached record highs and lows over the past two years. Stranded infrastructure As IEEFA noted in a recent report, gas price volatility is an abiding issue with the risk of stranded infrastructure assets. It is also however an opportunity for utilities such as GAIL and the gas sector to switch to cleaner, non-fossil fuel alternatives. Gas price volatility dampens demand, as do high prices. With the onset of Covid-19, LNG demand fell, and prices tumbled. In April 2020, the Japan Korea Marker (JKM), considered a benchmark for Asian LNG spot prices, reached its lowest point at $2/MMBtu. However, once the economic recovery began, gas supply couldn’t keep pace and prices started rising with the JKM peaking at $35/MMBtu on October 5, 2021. In the last few months, the Indian import spot LNG price, on average, has been in the range of $30/MMBtu. Given the unprecedented and unexpected sharp rises in gas prices last year, there can be little certainty that prices will stabilise at around $19-20/MMBtu in 2022, as predicted at the start of December. The futures for February indicate prices will remain above $25 till at least March 2023. In October last year, prices were expected to settle at $14-15 by May 2022 — an indication of the increasing unpredictability in gas markets. This itself is way beyond India’s affordability threshold of $10/MMBtu. Such price volatility can have major implications for demand, capital and infrastructure, especially in price-sensitive emerging economies such as India — raising the operating costs of downstream projects in the industrial, power and CGD sectors, and harming product competitiveness, utilisation rates and returns on investment. India is planning a massive expansion of LNG import infrastructure to spur gas demand. However, skyrocketing LNG prices and increased attention on the global warming potential of methane (the major component of ‘natural’ gas) will more than likely lead to a major risk of under-utilisation of this infrastructure with billions of dollars’ worth of investment becoming stranded, again demonstrating the policy disconnect. As IEEFA has previously noted, global gas supply/price volatility will likely continue to increase due to reduced drilling activity, financial instability in the oil and gas industry, and lower industry investment. An industry analysis shows that between 2016 and 2020, while Asia LNG spot prices averaged 27.2 per cent lower than Brent-linked prices, the volatility of LNG prices was much higher at 51 per cent compared to the Brent-based contract prices. Peak gas prices are challenging for producers and consumers and highlights a major problem with relying on gas as a “bridge fuel” to a lower carbon economy. Further, it adversely affects India’s import bill and current account deficit (CAD) — already deeply impacted by the pandemic — and puts the nation’s energy security at risk, making it a matter of urgency for the government to explore cleaner alternatives to gas. Biogas and biomethane As consumers contemplate substituting polluting fuels, the focus should be on developing renewable energy alternatives that would not only be more affordable but also help India transition to a low-carbon economy. Biogas and biomethane, options approved by the US Renewable Fuel Standard programme, are equivalent in quality to gas for cooking and transport and industrial use, respectively. For the
Indian Oil Corp to supply fuels to Sri Lanka in 4-5 month deal
Indian Oil Corp (IOC), the country’s top refiner and fuel retailer, will supply 12-13 fuel cargoes to Sri Lanka to help the island nation facing an energy crisis, the Indian company said in a statement to Reuters. IOC said it will supply gasoil, gasoline and jet fuel to Sri Lanka over the next 4-5 months. “The supplies shall be made under a $500 million line of credit extended by the government of India to Sri Lanka for purchase of fuels,” it said.
South Asia switches to expensive diesel on LNG crunch
Pakistan and Bangladesh are turning to expensive and dirty diesel fuel to generate electricity as the nations struggle to secure shipments of liquefied natural gas amid a supply crunch intensified by Russia’s invasion of Ukraine, Bloomberg reported on Wednesday. Pakistan’s diesel-fired power generation rose to the highest level in at least seven years in January, while LNG-based output dipped to the lowest in almost two years, according to government data compiled by Arif Habib Ltd. The two fuels each generated about 7 percent of the South Asian country’s electricity in January. That’s bound to continue as Pakistan has failed to find replacement LNG cargoes after long-term supplies were forced to cancel deliveries. “LNG supply looks tight at the moment and LNG prices were expected to remain elevated even before the invasion of Ukraine,” said Simon Nicholas, an analyst at the Institute for Energy Economics and Financial Analysis. “It’s likely Bangladesh and Pakistan will need to continue to use more diesel and oil in power generation.” Energy prices — already elevated amid a supply-demand imbalance as the w world recovers from the pandemic — have surged following the invasion and sanctions on Russia in response. Higher costs pose a particular burden for developing economies, such as Pakistan and Bangladesh, in their fight against climate change. The issue also highlights a growing problem with depending too much on LNG, which has suffered from a shortage as demand has largely outstripped supply over the last few years. It threatens to boost power costs across South Asia, increase government subsidies to support power payments and hurt the economic recovery in Pakistan and Bangladesh. Pakistan’s fuel costs doubled in January, compared with the same period a year ago, data from Arif Habib show. Diesel is the most expensive fuel for power generation in Pakistan, costing 14 percent more than fuel oil and 55 percent more than LNG-based generation, according to January data by the National Electric Power Regulatory Authority. Diesel use also comes as the nation’s refineries have been filled with fuel oil, meaning that there are other options for power, said Tahir Abbas, Arif Habib’s head of research. LNG Imports Liquefied natural gas imports into India, Pakistan and Bangladesh are set to hit a low point in February due to unaffordable spot LNG prices, according to BloombergNEF. A total of 39 cargoes arrived in January, the lowest since February 2019. BloombergNEF estimates the share of spot volume in South Asia’s total LNG imports fell to just 18 percent of January supply, down from 25 percent in the previous month. Bangladesh’s LNG supply crunch started after a mooring line at Summit Group’s floating storage and regasification unit broke down in November, said Mohammad Hossain, director general of Power Cell, a unit of Bangladesh’s Ministry of Power, Energy and Mineral Resources. Bangladesh extended downtime for compressed natural gas stations. Pakistan’s growing gas shortage this winter forced residents to turn to cylinders in Karachi and authorities offered discounts to make users switch from gas to electricity for heating. The nation’s domestic gas production has fallen by about a fifth over the past two years, making LNG supply even more crucial. Diesel is used only when there are constraints and largely for system stability and reestoration in instances of blackouts and outages, Pakistan’s energy ministry said in a response to questions. There is no requirement for diesel fuel for power generation until June, it said.
High crude prices may spur blending of fuels with ethanol
With a view to enhance ethanol production capacity in the country, the central government has notified two interest subvention schemes in 2018 and 2019 for molasses-based distilleries, under which interest subvention at the rate of 6% per annum or 50% of the rate of interest charged. With the price of Brent crude surging past $113 per barrel on Wednesday amid concerns over supply disruptions after Russia’s invasion of Ukraine, and a steep hike in domestic fuel prices looking imminent, the Centre’s ambitious ethanol blending programme (EBP) may get a shot in the arm. The country is dependent on oil imports to meet more than 80% of its oil demands. In 2020-21, state-run oil marketing companies sold 36.72 billion litres of ethanol-blended fuel, representing a foreign exchange saving of Rs 95.80 billion ($1.3 billion). According to the Indian Sugar Mills Association (ISMA), the country has a capacity to make 7.22 billion litres a year of ethanol currently, which will reach 15 billion litres a year by 2025. India’s ethanol blending has seen a sharp rise in the last five years, from 2.07% in 2016-17 to 8.10% in 2020-21. To help reduce its dependence on costly oil imports and provide farmers with an additional source of income, the Union government last year brought forward the target to achieve 20% ethanol blending with petrol from 2030 to 2025. “In 2020-21, the OMCs were supplied 3.02 billion litres of ethanol, from which the country achieved an average blending of 8.10%. We hope to see the country achieving 10% blending target by the end of FY2022 and 20% by 2025,” ISMA DG Abinash Verma said, adding that to meet the target, both the production and demand sides need to work in tandem. According to the Niti Aayog’s roadmap for ethanol blending, India’s net import of petroleum in 2020-21 was 185 million tonnes at a cost of $55 billion. “A successful E20 programme can save the country $4 billion per annum (Rs 300 billion),” it said. With a view to enhance ethanol production capacity in the country, the central government has notified two interest subvention schemes in 2018 and 2019 for molasses-based distilleries, under which interest subvention at the rate of 6% per annum or 50% of the rate of interest charged. As per the Niti’s ethanol production projections, India will have 10.16 billion litres for 20% ethanol blending by 2025-26, out of which 4.66 billion litres would be grain-based ethanol, while 5.50 billion litres would be molasses based. “We are confident of having enough production capacity to supply the required estimated 10.20 billion litres by 2025. The industry has shown a lot of interest in scaling up production, but what needs to be worked on now is to augment the demand said too, which includes getting augmenting the storage capacity in the depots for offtake of capacity and dispensing at retail pumps, which will can provide both E10 as well as E20 fuel. We also need the auto companies to come up with the right kind of cars and two-wheelers that are E20 compatible for the programme to be successful,” he said. When asked whether the E20 deadline will be preponed, especially in view of the heightened crude oil prices, the ISMA DG said that while production of ethanol can be preponed, the demand cannot be preponed as the auto manufacturers would need time to start rolling out vehicles that are E20 compatible. “From April 2023 onwards, E20 compatible vehicles will start rolling out and we expect that by 2025, as many as 25% to 30% of the vehicles on the streets would be E20 compatible. But to make 100% vehicles E20 compatible, we would need more time,” he said.
ONGC and its partners to decide operating Russia’s Sakhalin 1 project
India’s ONGC Videsh said it and its partners will decide on how to keep operating the Sakhalin 1 project over next few weeks, after Exxon Mobil’s decision to exit Russia’s oil and gas sector over Moscow’s invasion of Ukraine. Exxon, with a 30% stake, has operated the project in Russia’s Far East since production began in 2005. ONGC Videsh, and Japan’s SODECO own 20% while the remainder is held by Rosneft. ONGC Videsh, the overseas investment arm of India’s top explorer Oil and Natural Gas Corp., did not see “any immediate impact,” on the operation of the project due to Exxon’s decision, it said in an emailed statement.
Indian Gas Exchange IPO in the offing
India’s only gas exchange, IGX, which is a subsidiary of the energy exchange, IEX, will come out with an initial public offering, IEX’s Chairman and Managing Director, Satyanarayan Goel, told B usinessLine on Tuesday. IEX, which today has 47 per cent stake in IGX, was launched on June 15, 2020, to enable trading of natural gas — either imported or the gas that is outside of price-controls. Since its launch, IEX has sold stake in IGX to ‘strategic investors’ — ONGC, IOC, GAIL, Torrent, Adani and NSE. “There are many investors asking for stakes, but as a matter of policy, we have given stakes to these strategic investors only,” he said. “As per the regulations of PNGRB (Petroleum and Natural Gas Regulatory Board), we must bring down our stake to 25 per cent,” Goel said, adding that an “IPO is the most efficient mode” of doing so. A year-and-a-half has elapsed since IGX was incepted; the company has three-and-a-half years to comply with the regulations. Gas traded hits a high IGX today announced that it traded 2.27 million MMBTu of gas in February; the highest single day trade, 688,500 MMBTu, happened on February 15. In 2021-22, up till February, 8.8 million MMBTu of gas has been traded over the exchange, according to a press release from IGX. IGX facilitates delivery-based trades in six different contracts — Day-Ahead, Daily, Weekday, Weekly, Fortnightly and Monthly — at five different designated physical hubs – Dahej, Hazira, Dabhol, Jaigarh and KG Basin. Currently, the trades can be executed for three consecutive months in different contracts. Goel said on Tuesday that, “while IGX is doing better than what we had expected”, volumes have been affected by the rise in gas prices from about $4-5 per MMBTu to over $30, before coming down a little. However, he expressed confidence that prices would fall and volumes on the exchange would pick up. The press release of today said the average gas price discovered on the exchange in February was $24.6 per MMBTu. “The price discovered on the IGX is reflective of India’s gas demand and supply, including the LNG long-term, spot and domestic gas prices.” One upside for IGX is the ongoing ‘discovered small fields’ programme of the government, under which it auctions small and marginal oil and gas fields already discovered and found to be too small for biggies like ONGC. The third round of auctions is underway; after several months of delay, the award of fields to the best bidders is expected to happen by April. Companies who produce gas from these fields might find it more remunerative to sell their gas on the exchange, than either directly to customers or to the public sector gas trader, GAIL.
Exxon’s exit from Russia puts OVL in a fix
Exxon Mobil Corp’s decision to exit Russia has put India’s flagship overseas firm ONGC Videsh in a fix as it is a partner in the global energy giant-operated Sakhalin-1 oil fields in Far East Russia, sources said. ONGC Videsh Ltd (OVL) and three other state-owned Indian firms hold 49.9 per cent stake in a separate Vankor oilfield in west Siberia but that investment will not be impacted as they repatriated their dividend income from last year in January 2022 and would not immediately face issues because of Russia being cut off from the global payment system SWIFT over its Ukraine invasion. ExxonMobil holds 30 per cent stake in the Sakhalin-1 offshore oil assets, where ONGC Videsh Ltd — the overseas investment arm of state-owned Oil and Natural Gas Corporation (ONGC) — has a 20 per cent interest. The field, which produced some 227,400 barrels of oil a day (11.35 million tonnes a year) and over 12 billion cubic metres of natural and associated gas in 2021, is operated by ExxonMobil. While it has not put a timeframe for leaving the venture, the exit of ExxonMobil would mean technical manpower and expertise would no longer be available at the project, three sources with direct knowledge of the matter said. In all likelihood, Russia’s Rosneft, which holds 20 per cent participating interest in the fields, will take over Exxon’s share, they said. The Sakhalin-1 project, where the partners have so far invested USD 17 billion in developing the reserves lying below the sea that freezes during winter, is regarded as a technical marvel. It involved developing three oil and gas fields off Sakhalin — Odoptu, Chayvo and Arkutun-Dagi — by drilling record-setting wells from shore that bored down and sideways for up to seven miles to reach the reservoirs that had frustrated the Soviets when they discovered oil there in 1979. OVL joined the project in 2001 and ExxonMobil began pumping oil from the fields that were considered too deep and remote to produce, in 2005. Sources said ExxonMobil has publicly stated that it is starting a process to discontinue operations and developing steps to exit the Sakhalin-1 venture. It would no longer invest in new developments. ExxonMobil, which joined BP and Shell to announce exit from Russia over Moscow’s invasion of Ukraine, has told foreign managers to leave the project, sources said, adding a couple of wells may be on course of being shut down. The majority of the managers at the project are foreign nationals while US contractor Parker Drilling is in charge of almost all drilling operations, they said, adding ExxonMobil relies on other US and international contractors for operations. The foreign staff in all likelihood will leave the project over the next few days, sources said. Besides ExxonMobil and OVL, Japanese consortium Sodeco has a 30 per cent interest in Sakhalin-1 and Russian producer Rosneft has the remaining 20 per cent. ExxonMobil and Rosneft have been working on a plan to commercialise remaining natural gas reserves by exporting them to international markets as liquefied natural gas (LNG). Non-associated gas from the Chayvo field is planned to be sent by a new pipeline to a 6.2 million tonnes per annum liquefaction facility to be built at the port of De Kastri on the Russian mainland.
Europe Can Survive Next Winter Without Russian Gas
Russia’s invasion of Ukraine threw Europe’s dependence on Russian natural gas into sharp relief. The European Union is drafting measures to reduce its reliance on Russian energy, while various European countries, including the biggest economy, Germany, are revising their strategic energy policies, aiming to reduce their energy security vulnerability. It was this vulnerability that has stopped the EU, the U.S., and allies from slapping sanctions on Russian energy exports (for now). Europe receives some one-third of its natural gas from Russia, but the dependence varies among EU members. Germany is 50-percent reliant on Russian gas, and Italy imports 40 percent of its gas needs from Russia. Southwest European countries Spain and Portugal do not import any Russian gas, but southeast European countries and Russia’s neighbors to the west, Estonia and Finland, are 100 percent or nearly 100 percent dependent on Moscow for their natural gas supply. As the war in Ukraine threatens to cut off Russian gas supply—either in the form of sanctions or a Putin retaliation to sanctions—Europe realized that ensuring energy security would mean weaning itself off Russian deliveries in the quickest way possible, even at a high economic price. Ensuring gas for next winter should not be a problem, analysts and the European Commission say. The question is, what will Europe do for the winter after that—and all the following winters in the long term—if it wants to reduce its dependence on Russian gas and not shape its security or sanctions policy in fear of being cut off from its largest source of gas. This winter is nearly at its end, and European gas in storage is back to the five-year range. With restocking during the summer, Europe could go without Russian gas next winter, according to Wood Mackenzie. “From record lows at the start of winter, storage levels have now re-enter[ed] their five-year range, albeit on the lower side, and are on track to be in a more comfortable position by the end of March,” Kateryna Filippenko, principal analyst, Europe gas research, at WoodMac, said. “It is our current assessment that the EU can get through this winter safely. At the moment, gas flows from East to West continue, LNG deliveries to the EU have increased significantly, and the weather forecast is favourable. The use of gas from storage has slowed down and we are still around 30% of storage capacity filled,” European Energy Commissioner Kadri Simson said on Monday. EU member states need to collectively ensure a certain level of gas storage in their regions and to conclude solidarity agreements to send gas where it’s most needed, Simson said. “The war against Ukraine is not only a watershed moment for the security architecture in Europe, but for our energy system as well. It has made our vulnerability painfully clear. We cannot let any third country destabilise our energy markets or influence our energy choices,” the commissioner said. “The European Union can manage without Russian gas next winter, but must be united in taking difficult decisions, accepting that in many cases it won’t have enough time for perfect solutions,” analysts at European think tank Bruegel wrote in an analysis this week. In the wake of the Russian invasion of Ukraine, Germany announced it was changing course “in order to eliminate our dependence on imports from individual energy suppliers,” German Chancellor Olaf Scholz said on Sunday. Germany will build two LNG import facilities, at Brunsbuettel and Wilhelmshaven, and look to speed up the installation of renewable energy capacity to have 100-percent renewable power generation by 2035. For Europe, managing without Russian gas “will require improvisation and entrepreneurial spirit,” analysts at Bruegel say. “The main message is: if the EU is forced or willing to bear the cost, it should be possible to replace Russian gas already for next winter without economic activity being devastated, people freezing, or electricity supply being disrupted,” they noted. “But on the ground, dozens of regulations will have to be revised, usual procedures and operations revisited, a lot of money quickly spent and hard decisions taken. In many cases time will be too short for perfect answers.”
Italy Halts Funding For $21 Billion Arctic LNG 2 Project
Italy has halted its share of the financing for the Arctic LNG 2 project, as Western companies and countries continue to sell their stakes in Russian energy projects, even absent of energy-related sanctions. Tankers carrying Russian LNG to Europe have changed course, oil majors such as Shell, BP, and Exxon have pulled out of Russian oil projects at great expense, and now, Italy has suspended its financing for the Arctic LNG 2 project, owned by Russian gas producer Novatek. The project, estimated at $21 billion, is just one of the many projects that is losing foreign backing, even though Russia’s energy exports have thus far been exempt from sanctions. Italy, fearing more sanctions, is now rethinking its loan to the project, which some estimate at $560 million. Italy had only recently decided to help finance the project. The loan for the project had not yet been dispersed. The agreement to finance part of the project, however, remains intact. The latest move highlights just how much of a pariah Russia has become on the world stage after its invasion of Ukraine, and could put a damper on some of Russia’s energy projects. Arctic LNG 2 was destined to be up and running by 2023, reaching full capacity by 2026. Arctic LNG 2 is expected to produce 20 million tonnes of LNG annually. In addition to Russia’s Novatek, Arctic LNG 2 shareholders include TotalEnergies, CNPC, CNOOC, and Japan Arctic LNG. TotalEnergies, with a 10% stake, is one European oil major that has not decided to quit its Russian operations. The Arctic LNG 2 project was already controversial even before Russia’s invasion of Ukraine, with the European Parliament stating that it was concerned about EU members’ support of the project because it was not compatible with climate targets.
Ukraine invasion: Shell pulls out of energy investments in Russia
Shell says it pulling out of Russia as President Vladimir Putin’s invasion of Ukraine costs the country’s all-important energy industry foreign investment and expertise. Shell announced its intention Monday to exit its joint ventures with Gazprom and related entities, including its 27.5 per cent stake in the Sakhalin-II liquefied natural gas facility, its 50 per cent stake in the Salym Petroleum Development and the Gydan energy venture. Shell also intends to end its involvement in the Nord Stream 2 pipeline project. “We are shocked by the loss of life in Ukraine, which we deplore, resulting from a senseless act of military aggression which threatens European security,” said Shell’s chief executive officer, Ben van Beurden. The move comes as day after rival BP announced plans to shed its almost 20 per cent stake in Rosneft, which is controlled by the Russian state. Also Monday, Norway’s Equinor said it would halt new investment in Russia and begin selling its holdings in the country. Shell’s most important investment in Russia is its stake in the Sakhalin-II project in the waters near Sakhalin Island off Russia’s east coast. Japan-based Mitsui owns 12.5 per cent of the project and Mitsubishi holds 10 per cent.