Plans afoot to build strategic natural gas reserve
India is drawing up a plan to build a strategic natural gas reserve with a capacity to store up to 4 billion cubic metres (BCM) of imported gas, which can be used in case of supply emergencies and to smoothen the domestic market, according to people familiar with the matter. After oil minister Hardeep Singh Puri recently gave a green signal to the idea of setting up the gas reserve, the oil ministry directed Oil and Natural Gas Corp (ONGC), Oil India and GAIL to jointly prepare a detailed feasibility report on the same, people said. The companies are expected to submit the report in three months. India has evaluated building strategic gas storage in the past as part of its energy security plan but didn’t go ahead with it due to its prohibitive costs. The geopolitics-driven frenzy in the global gas market last year, which disrupted India’s gas imports and forced some factories to cut production, has brought a strategic policy rethink, people said. The 3-4 BCM gas storage capacity being targeted now can cost $1-2 billion to build, the person cited previously said. India, which consumed 60 BCM of natural gas last fiscal year, aims to increase the share of gas in its energy mix to 15% by 2030 from the current 6%. A large multi-location storage, a well-laid pipeline network, and a mature gas exchange can help develop the domestic gas market. Large gas storage can also help India become the regional hub and supply to neighbouring countries like Sri Lanka, Bangladesh and Myanmar in the future, the person said. The feasibility report will present cost estimates, probable locations, construction timelines, and the business and financial models for the reserves, he said. Depleted wells of ONGC and Oil India could be used for the storage, he said, adding that ONGC has already identified two such wells in Gujarat while Oil India is aiming to do the same in the North East. The report is expected to suggest the most optimal storage model and answer questions on whether a strategic or commercial model or a mix of both would be suitable for the country. It would also offer details on the commercial model and the government support needed to make it financially viable, the person said. Who can be permitted to invest in such storage and how they can recover their investments will also be part of the report. India aims to become a gas-based economy, and, with gas consumption expected to balloon in the future, it would need storage to tide over the short-term market challenges. The country imports about half the gas it consumes. Major gas-consuming economies like Europe and China have large artificial gas storages, which help manage domestic demand.
Supreme Court upholds gas power plant’s entitlement to fixed charges
The Supreme Court of India (“Supreme Court”) in the case of Maharashtra State Electricity Distribution Company Limited v. Ratnagiri Gas and Power Pvt. Limited & Ors. upheld the decisions rendered by both Central Electricity Regulatory Commission (“CERC”) and the Appellate Tribunal for Electricity (“APTEL”) that Ratnagiri Gas and Power Pvt. Limited (“RGPPL”) is entitled to fixed charges for the duration the Maharashtra State Electricity Distribution Company Ltd. (“MSEDCL”) did not schedule electricity from RGPPL. MSEDCL did not schedule power from RGPPL (for a certain duration) as RGPPL executed an alternate arrangement with Gas Authority of India Ltd. (“GAIL”) for supply of Recycled Liquefied Natural Gas (“RLNG”), without taking MSECCL’s permission. RGPPL declared capacity for its gas power plant based on RLNG (to be) supplied by GAIL. The issue before CERC, APTEL and Supreme Court was whether MSEDCL should pay fixed charges to RGPPL for capacity declared based on RLNG (to be) supplied by GAIL. CERC and APTEL recognized that this alternate arrangement was executed due to shortage of domestic gas supply since September 2011. Both CERC and APTEL held that provisions of the power purchase agreement (“PPA”) between MSEDCL and RGPPL allowed RGPPL to declare capacity based either on liquid gas or RLNG and it was only for payment of variable charges that MSEDCL’s permission was required for executing agreements for gas supply/transport.
CONCOR ties up Indraprastha Gas to explore possibility of LNG/LCNG infra at terminals
Railway PSU Container Corporation of India Ltd has signed an agreement with Indraprastha Gas Ltd to explore the possibility of setting up LNG or LCNG infrastructure at its terminals in Uttar Pradesh and Gujarat. This strategic partnership aims to revolutionise the logistics sector replacing diesel with natural gas, the Container Corporation of India Ltd (CONCOR) said in a statement. “CONCOR and IGL have signed a memorandum of understanding (MoU) to explore the possibility of setting up LNG/LCNG infrastructure within the premise of CONCOR terminals. Initially, both LNG and LCNG facilities shall be installed at Dadri (Gautam Budh Nagar) terminal of CONCOR,” the statement said. CONCOR and IGL also agree to explore the possibility of transportation of LNG in future through railway rakes from LNG terminals near sea ports like Dahej in Gujarat to the desired locations within India. The MoU signifies the commitment of both CONCOR and IGL to reduce carbon emissions and promote a cleaner, greener future for the transportation industry. LNG trucks emit significantly lower levels of greenhouse gas emissions compared to conventional diesel trucks, contributing to a cleaner environment and aligning with global sustainability goals. As part of the MoU, both entities shall jointly examine the possibility of using LNG-fired engines in place of existing diesel-fired engines, in various terminals of CONCOR. Sanjay Swarup, Chairman & Managing Director CONCOR said, “CONCOR is dedicated to embracing innovative solutions that not only enhance operational efficiency but also align with our responsibility towards the environment. The partnership with IGL for LNG truck refuelling is a testament to our commitment to a greener future. K K Chatiwal, Managing Director, IGL, stated, “This collaboration marks a significant step forward in our commitment to environmental sustainability. By creating the required LNG infrastructure, we aim to set new benchmarks for eco‐friendly transportation in the industry.”
ONGC Set To Resume KG Basin Production In Boost For India’s Energy Self-Reliance
The state-owned Oil and Natural Gas Corporation will start production of crude oil from its flagship deep-water project in Krishna Godavari Basin next week. The production will help India save nearly Rs 110 billion per year. India imports 85% of its crude oil requirements and about half of its natural gas needs. ONGC also plans a capital expenditure of Rs 1000 billion for petrochemical projects by 2028-2030. The investment would be used for two separate projects. The movement in KG Basin is considered very significant, say top officials of the Ministry of Petroleum and Natural Gas. The production from its much-publicised, deep-sea asset is expected to be a shot in the arm for the explorer and help reverse the low productions bothering the state-owned hydrocarbon behemoth. The increase in domestic output will also help save outflow of precious foreign exchange on import of crude oil. At current Brent crude price of $77.4, this output alone will save Rs 290 million every day (at Rs 83.29 to $1) or a staggering Rs 106 billion on an annual basis. Initially, oil production from the basin was scheduled to start from November 2021, but the deadline was delayed several times. In short, this will be ONGC’s first significant oil producing asset on the East Coast. The KG-DWN-98/2 block has a number of discoveries that have been clubbed into clusters. It is situated 35-km off the coast of Andhra Pradesh in Bay of Bengal with water depths up to 3,200 metres. The discoveries in the block are divided into three clusters — 1, 2 and 3. Cluster 2 is being put to production first. Besides crude oil output, 7-8 mmscmd (million metric standard cubic metres per day) of gas will start to flow from the middle of calendar 2024. The hydrocarbon giant, it is reliably learnt, will press in service as many as 75 rigs. ONGC plans to start producing from 3 to 4 wells in the initial phase, when the production could be 8,000 to 9,000 barrels per day. The company actually aims to drill 541 oil wells in FY24, up from 461 wells drilled in the last fiscal. The production from the KG-DWN-98/2 block will add to India’s domestic production and help reduce the dependence on imports to some extent. India currently produces approximately 600,000 barrels of oil per day. Thus, at peak, the cluster-2 project will account for 7% of India’s output. This is the start and peak oil production of 45,000 barrels per day is expected sometime in financial year 2024-25, said a top ministry official. At the peak output of 45,000 barrels per day, this will be the third most prolific offshore asset for ONGC after Mumbai High and Bassein & Satellite fields, both on the West Coast, the official said. With a combination of fresh output and enhanced recoveries, ONGC group’s oil production is likely to rise to top 25 million tonnes in FY25 compared to 21.5 million tonnes in FY23. ONGC has seen a fall in its crude oil output as most of the assets are mature and natural decline has set in. Even as ONGC is investing in technology for enhanced oil recovery and improved oil recovery, the commencement of output from new assets like the KG block will certainly reverse the trend of falling output. In Q2, ONGC’s consolidated net profit soared 142.4% at Rs 165.53 billion. Earlier, ONGC had announced that it will bring in an equity partner in ONGC Petro additions Ltd. or OPaL by financial year 2026-2027. ONGC had then said it wants to infuse Rs 183.65 billion in OPaL, and make OPaL a joint venture. OPaL is a joint venture between ONGC, GAIL (India) and Gujarat State Petroleum Corporation Ltd.
India sets first benchmark price for biomass pellets
India has rolled out its first benchmark price for biomass pellets to promote capacity additions and encourage co-firing with coal. November 21, 2023: India’s power ministry has announced a benchmark price of 2.27 rupees/1,000 kcal ($0.027/1,000 kcal) for non-torrefied biomass pellets applicable to northern India excluding the national capital region. The pellets should have moisture content below 14pc and a gross calorific value between 2,800-4,000 kcal/kg. The price excludes goods and services tax and transportation costs, the ministry said recently. The price, set up on the recommendations of a price benchmarking committee, is set for a year effective 8 November. Thermal power plants in the region are advised to adhere to this benchmark price. The ministry amended a policy for the country’s utilities to co-fire biomass with coal in June, by delaying the start date and announcing the setting up of a committee to implement price benchmarking and biomass purchases. Indian utilities in the original policy, announced in October 2021, were told to co-fire 5pc biomass from October 2022, in a move aimed at reducing coal consumption and curbing pollution. Co-firing was originally set to increase to 7pc from October 2023 for two categories of power plants — those with a bowl mill or with a ball and race mill. The revised policy, announced by the power ministry on 16 June, requires all coal-based thermal power plants with bowl mills to use a minimum 5pc blend of biomass pellets made primarily from agricultural residue with effect from the start of India’s 2024-25 fiscal year from 1 April, increasing to 7pc from the start of 2025-26. Plants with ball and race mills should co-fire the same percentages of torrefied biomass pellets made from agricultural residue during the same timeframe. The policy for co-firing will be valid for 25 years or until the useful life of a power plant, whichever is earlier, the power ministry previously said. The extent of co-firing will be reviewed periodically. India has surplus biomass supplies of about 230mn t/yr, largely from agricultural residue, the power ministry previously said. The surplus has prompted the country to look at the potential for exporting biomass. The government amended its trade policyin February this year to allow exports of biomass, as the country eyes more investment in biomass manufacturing capacity and technology.
Russia Removes Gasoline Export Ban As Domestic Market Stabilizes
Russia has lifted its gasoline export implemented in mid-September, citing a supply surplus of some 2 million metric tons, Reuters reports. The lifting of the export restrictions follow a similar move to suspend restrictions on diesel exports by pipeline during the first week of October. Reuters cited the Russian energy ministry as saying on Friday that domestic market saturation had been ensured over the past two months, creating a surplus of motor gasoline. The ministry said it could reimpose export bans if that surplus vanished. Russia restricted diesel and gasoline exports on September 21 in an effort to stabilize domestic fuel prices in the face of soaring prices and shortages as crude oil rallied and the Russian ruble weakened. Prior to implementing the bank, Russia had raised mandatory supply volumes for motor gasoline and diesel fuel to deal with a supply crunch. The ban on diesel was lifted on the condition that at least 50% of producer supplies went to the domestic market. Russia’s diesel exports had been redirected from the European Union following the bloc’s embargo in February this year, to markets in Turkey, the Middle East, Africa and South America. In the meantime, Russia will continue its voluntary oil output cuts through the end of this year in coordination with OPEC+; however, the gasoline and diesel bans had made that commitment more challenging. Data from the first week of November showed that Russia’s seaborne diesel exports had fallen by 11% in October, compared to September. According to the Carnegie Endowment for International Peace, Russia’s gasoline and diesel bans were “partly the result of efforts to protect domestic fuel prices from the vagaries of the market, and partly a consequence of government infighting. It’s also a stark demonstration of how the stresses of the war in Ukraine are revealing themselves in unexpected places.” Also on Friday, the Russian State Duma (parliament) formally reinstated damper payments subsidies to oil refineries, Reuters reported, in an effort to further encourage sales on the domestic market over higher-priced exports.
India’s crude oil imports to rise in November, December due to festival season, industrial activity
India’s crude oil imports are expected to grow from October level during the remaining two months of the calendar year in line with the ongoing festival and marriage season, which also witnesses an uptick in industrial, construction and farm activities. Analysts and trade sources said that domestic oil marketing companies (OMCs) have increased refinery runs for the remainder of 2023 to meet the growing demand for auto fuels, bitumen, fuel oil and other refined petroleum products. A top official with a public sector OMC explained, “Traditionally, consumption rises during October-March in line with the festival and marriage season as well as industrial and construction activity. Besides, agricultural activity for Rabi season also picks up. This coupled with some exports will push demand.” Energy intelligence firms Kpler and Vortexa also expect crude imports by the world’s third largest energy consumer to grow in November and December this year. Similarly, OPEC in its latest monthly oil market report for November said, “India’s crude imports fell further to an average of 4.3 million barrels per day (mb/d) in September, the lowest in a year, although are expected to recover with the start of Q4 2023.” Rising imports Kpler’s Lead Analyst (Dirty Products and Refining) Andon Pavlov said considering that maintenance season is now starting to wane and seasonally demand at home starts to pick up, following the monsoon season and as visible in the latest Petroleum Planning and Analysis Cell (PPAC) data, refinery runs are also going to increase gradually over November and December, pushing import requirements higher as well. India imported 4.66 mb/d of crude in October, which is almost flat compared to September, Kpler data show. “In our books, we see (refinery) runs standing at 5.3 Mb/d and 5.45 Mb/d in November and December, respectively, some 500,000 barrels per day (b/d) and 130,000 b/d higher Y-o-Y over said months, (respectively), mainly due to a baseline effect from last year,” he told businessline. However, Pavlov said, considering that discount on Russian imports has diminished somewhat over the past months and in light of seasonal tightening of the Russian crude balance towards the end of year, as refinery runs seasonally increase, it seems like the share of Russian crude is going to remain in check at best. Discount on Russian crude to India continues to be lower at around $4-5 per barrel in May-August 2023 against $6-10 earlier. Vortexa’s chief analyst for Asia Pacific, Serena Huang said, “I expect India’s crude imports to continue rising through to December, with demand supported domestically by the festive season and exports.” India’s oil demand outlook in Q4 2023 should continue to benefit from strong annual GDP growth in 2023, combined with robust manufacturing activity and a proposal by the government to increase capital spending on construction, OPEC said. Besides, the post-monsoon harvesting season and construction activity are also expected to support oil demand growth. In addition, the forward-looking indicators show strong manufacturing and services PMIs, suggesting prospects for healthy oil demand in the near term, it added. “In Q4 2023, oil demand is projected to grow by 243,000 b/d, Y-oY. Distillates are expected to be the driver of oil demand growth, supported by harvesting, construction and manufacturing activity. Additionally, traditional festivities are expected to support mobility and boost gasoline demand, while increasing air travel is expected to support jet/kerosene demand,” OPEC projected. Similarly, S&P Global Commodity Insights said, “Overall, India’s oil demand is expected to grow by 258,000 b/d in 2023, revised higher by 9,000 b/d from last update on strong diesel sales. Middle distillates, gasoil, and kerosene/jet fuel combined will account for more than 50 per cent of the growth, with gasoline and naphtha together to contribute 27 per cent of the growth.” The demand for petrol and diesel rose to a four-month high in October, while jet fuel sales surged to their highest in the current financial year and calendar year as rising industrial and construction activity coupled with the onset of the festival season boosted sales.
Gas Infrastructure Needs to be Ready for Clean Hydrogen
As green hydrogen becomes an ever more important clean energy source, governments and energy companies must prepare for a steep incline in production in the coming years and ensure they have the correct infrastructure to transport it. Some regions of the world are already establishing major hydrogen corridors, such as the Spain – Netherlands link in Europe. Adapting new natural gas developments to be suitable for hydrogen transportation could save companies money and time in the long term, as well as support the transition away from fossil fuels to renewable alternatives. This month, the CEO of Italgas, Paolo Gallo, emphasised the importance of constructing gas infrastructure that is capable of transporting hydrogen as a means of meeting decarbonisation goals. Gallo stated, “Today we are moving around natural gas, but tomorrow we will have biomethane [and] clean hydrogen that will be used to decarbonize the system… So, it’s extremely important that the infrastructures are ready to accept different kinds of gases in [a] blending situation.” Green hydrogen, produced using renewable energy sources rather than fossil fuels to power electrolysis, is being viewed as increasingly important for accelerating the global green transition. Unlike wind or solar power, green hydrogen is a versatile carrier that can be used in a range of ways, such as in fuel for transportation. While most hydrogen is produced using fossil fuels at present, favourable government policies and increased pressure on energy companies to decarbonise are expected to lead to a boom in green hydrogen production over the coming decades. Gallo is not the first to suggest the repurposing of existing infrastructure, with several energy companies around the globe exploring ways to adapt existing pipelines to make them suitable for transporting hydrogen. Many European countries are aiming to use existing gas infrastructure to transport hydrogen, with several recent studies and pilot testing phases showing positive results. The use of existing pipelines can reduce hydrogen transport costs but pipelines must be assessed to see whether they’re suitable for hydrogen transportation, taking into account issues such as leakage, leakage detection, effects of hydrogen on pipeline assets and end users, corrosion, maintenance, and metering of gas flow. The potential use of gas pipelines for transporting hydrogen is becoming an increasingly popular topic as many governments accelerate plans to increase their natural gas production and infrastructure. This is being seen in the U.S., which, controversially, has an LNG project pipeline of 13 facilities along the US Gulf Coast in Louisiana and Texas. Canada is also constructing its first LNG transport facility, after years of pressure from energy companies. This reflects the global sentiment that natural gas will be critical for achieving the green transition. The EU ruled last year that natural gas will be used as a transition fuel in the mid-term shift to green alternatives as a means of moving away from more polluting fossil fuels, such as oil and coal. This has driven many energy companies to announce new gas projects for the next decade. This regional production drive was further accelerated by gas shortages in Europe and North America following the Russian invasion of Ukraine and subsequent sanctions on Russian energy last year. As companies develop new natural gas projects with support from state governments – potentially at odds with national climate policies – they should consider the potential for new pipelines to be used for transporting alternative energies, such as green hydrogen and ammonia, to ensure new infrastructure does not go to waste as the demand for gas eventually wanes. In the U.S., the Department of Energy’s Hydrogen and Fuel Cell Technologies Office (HFTO) launched the HyBlend initiative in 2021 to address technical barriers to blending hydrogen in natural gas pipelines to support the DoE’s H2@Scale vision for clean hydrogen use across multiple sectors in the economy. The U.S. has around three million miles of natural gas pipelines and more than 1,600 miles of dedicated hydrogen pipelines. The HyBlend team will test gas pipelines across the country to see their suitability for transporting hydrogen in different blends. This year, Open Grid Europe (OGE) announced that the first long-distance gas pipeline in Germany is being converted for hydrogen use. The 46km pipeline in the northwest of the country will be ready to transport hydrogen from 2025. The project is part of the GET H2 Nukleus project and is being funded by the EU’s Important Project of Common European Interest (IPCEI) initiative. The adaption of the pipeline is expected to help companies in heavy industry and medium-sized businesses connect to the hydrogen supply. Several new natural gas facilities are being constructed to support mid-term energy security en route to a green transition. At the same time, many companies around the globe have announced plans to develop their green hydrogen production over the coming decade, with demand expected to rise significantly over the next few years. Energy companies and governments must now use this opportunity to develop pipelines that can be used for the transport of both natural gas and green hydrogen to save money and time in the future and better support a green transition.
Has the Energy Transition Hit a Wall?
Wind power stocks are tanking. So are solar power stocks. Germany’s government just agreed to underwrite a 15-billion-euro bailout for Siemens Energy after its wind power subsidiary booked massive losses. The list could continue. The movers and shakers in the energy space are finding it increasingly hard to move and shake. It was easy to anticipate this development, yet, many choose to ignore the signs, and now the sector may suffer more before the growing pains ease. One common theme in the wind, solar, and EV space is the theme of rising costs. This was perhaps the easiest development to anticipate in the progress of the energy transition. After all, everyone was forecasting a massive surge in the demand for various raw materials and technology to enable that transition. There is one guaranteed thing that happens when demand for something rises: prices also rise before the supply response kicks in. This is a universal truth for all industries and there was no reason to expect that the transition industry would be an exception. Indeed, demand for raw materials necessary for solar panels, wind turbines, and EV batteries rose, but supply was slow to catch up, which led to higher prices. For a while, many pretended this was not the case, possibly hoping the cost inflation would blow over before investors noticed it. Denmark’s Orsted, which suffered some of the worst market cap losses in the transition space, just this June published an upbeat outlook for the year and the medium term, expecting strong capacity additions growth and a return on capital employed rate of an average 14% for the period 2023 to 2030. The same month the head of the company complained loudly about the rising costs of building offshore wind in Britain and asked for more subsidies. Five months later, Orsted had booked $4 billion in impairment charges from its U.S. business and had canceled two offshore projects there. CEO Mads Nipper called the situation in wind power “a perfect storm”. Many have blamed the higher costs on the legacy of the pandemic lockdowns—broken supply chains, delays, and other obstacles to the smooth movement of goods and materials. Yet when it comes to the transition, the current state of affairs is more likely part of the same vicious circle that is holding back the EV revolution that fans of Tesla keep predicting. This circle is best illustrated in the case of EV chargers. Since range anxiety is one of the biggest concerns of prospective buyers, there must be enough chargers for this anxiety to subside. But charger companies wouldn’t build chargers unless they are certain there will be enough EVs on the roads to make these chargers profitable. The situation is similar in copper mining—perhaps the most fundamental industry for the energy transition. After all, the transition is conceived of as a shift to almost full electrification and you cannot have electrification without a lot of copper. Instead, copper miners are reluctant to splurge on new exploration. Miners don’t have enough certainty about future demand, despite all the upbeat forecasts. Whatever market prices show, if the transition gains momentum as planned, the copper shortage will only be a matter of time. Another obstacle is demand. There seemed to be an assumption among transition planners that demand would be given; but it hasn’t been. EV makers now find themselves revising their plans as demand falls short of targets. In June, forecasts for Germany were that demand for solar installations would surge by double digits in 2023. Two months later, an inverter maker warned that demand had actually dropped in the third quarter, and the outlook for Q4 was not particularly encouraging. In wind, projects are being canceled because project leaders are asking for much higher prices than previously agreed with funding governments. Many are blaming higher interest rates for the cost inflation that sank their shares. But interest rates are something that all industries have to deal with, and those other industries don’t have the privilege of counting on generous government subsidies. Yet wind, solar, and EVs can’t take off even with those subsidies. This puts the future of the transition in a new perspective: something that many observers foresaw but were dismissed as climate deniers. The transition will be neither as fast nor as smooth—or as cheap—as initially expected. It will take a long time; it will be uneven, and it will be expensive. “There’s this notion that it is going to be a linear energy transition,” Daniel Yergin, S&P Global vice chairman and a veteran energy chronicler, told the Wall Street Journal. “It’s going to unfold in different ways in different parts of the world.”
“I am waiting for Thank You”: S Jaishankar On India Softening Oil Markets
Asserting India’s role in stabilising global oil and gas markets through its strategic purchase policies amid the Russia-Ukraine war, External Affairs Minister S Jaishankar noted that the purchase policies of India managed “global inflation”. During a conversation hosted by the High Commission of India in London, titled ‘How a billion people see the world,’ Mr Jaishankar discussed India’s impactful position in global affairs. EAM Jaishankar said, “So we’ve actually softened the oil markets and the gas markets through our purchase policies. We have, as a consequence, actually managed global inflation. I’m waiting for the thank you.” The minister explained that India’s approach to oil purchases prevented a surge in global oil prices, preventing potential competition with Europe in the market. He elaborated, “When it comes to the purchase…I think the global oil prices would have gone higher because we would have gone into the same market to the same suppliers that Europe would have done and as we discovered Europe would have outpriced us.”