Fuel prices stay static, petrol ends month without revision
Petrol completed a month without revision in its retail prices as oil marketing companies (OMC) decided against changing its pump price on Thursday as international product market remained subdued while crude prices remained static. Along with petrol, oil companies also kept the diesel prices unchanged even though the product has got back on demand cycle this month. With this, Petrol prices have now been unchanged for 30 days at a stretch while diesel prices were the same for the 20 consecutive days. Price of petrol in the national capital stood at Rs 81.06 per litre. In Mumbai, Chennai and Kolkata, the fuel was sold for Rs 87.74, Rs 84.14 and Rs 82.59 per litre, respectively. Diesel prices in Delhi, Mumbai, Chennai and Kolkata continues to be at at Rs 70.46, Rs 76.86, Rs 75.95 and Rs 73.99, respectively. Oil sector experts said that with global oil prices under pressure from slowing demand in the second wave of Covid-19 pandemic sweeping several western countries, crude price could fall in coming days. If this holds on for a week or so, there could be positive gains for auto fuel consumers. Global crude prices are holding close to $42 a barrel now. It has been hovering between $40-42 a barrel for over a month now. But with lower oil demand and rising inventory, there is fear among oil producing companies that crude prices may start falling again.
Gujarat to Empanel Contractors for Biogas Projects
The Gujarat Energy Development Agency (GEDA) has floated an empanelment tender for large-sized biogas projects in the state. The contract will also include the running and maintenance of the project for 10 years. The last date to submit the bids is November 02, 2020, and the opening of bids will take place on the same date. In its proposed amendments to its renewable purchase obligation (RPO) regulations in August, biogas has been brought under the ambit of renewable sources, which was earlier not included in the list . Interested bidders will have to submit an amount of ₹100,000 (~$1,362.6) as the registration fee to participate in the competitive bidding process. The contractor should complete and commission the project within four months. To participate in the competitive bidding process, the bidder should have successfully constructed at least three large biogas projects of a minimum capacity of 25 m3/day each. They should also have executed a biogas project worth at least ₹2 million (~$27,253) in the last three years. As per the tender document, the payment of subsidy to the authorized contractor will be made in three installments. The first and second installations will be 40% each, while the last installment would cover 20% and will be paid after the commissioning and one-month training for operation and maintenance. The central government is also promoting the use of compressed biogas as an alternative green transport fuel for the efficient management of biomass and organic waste. Biomass and organic waste sources like paddy straw, farm stubble, agricultural residue, cattle dung, sugarcane press mud, distillery spent wash, municipal solid waste, and sewage treatment plants offer huge potential for biogas production. The oil public sector units launched the Sustainable Alternative Towards Affordable Transportation (SATAT) initiative on October 1, 2018. SATAT initiative is expected to have the potential of addressing environmental problems arising from landfill emissions, farm stubble burning, and bringing down the dependency on oil imports. Until June 2019, oil and gas marketing companies are said to have awarded letters of intent (LoIs) to 344 plants for the production and supply of compressed biogas. Early this year, the Ministry of New and Renewable Energy (MNRE) released a list of technically qualified organizations for independent third-party evaluation study for the New National Biogas and Organic Manure Program and the Biogas based Power Generation (Off-grid) and Thermal Energy Applications Program (BPGTP).
China’s Guangzhou Gas says LNG import terminal to begin operations by H2 2022
China’s Guangzhou Gas Group said on Wednesday the liquefied natural gas (LNG) storage tank and jetty it’s building on the southern coast in Guangzhou is expected to begin commercial operation by second-half 2022, with initial annual throughput of 1 million tonnes. In slides presented at a gas conference in Shanghai, the company said it would begin issuing tenders to buy over 1 million tonnes per year of LNG for the medium and long term in 2021. Local government-backed Guangzhou Gas, one of China’s fast-growing players in the LNG sector outside the national state giants, had earlier planned to build a 2 million tonnes per year LNG terminal by 2020. Phase 1 of the terminal project on the southern coast includes building two 160,000 cubic metre LNG storage tanks, while Phase 2 includes building two 200,000 cubic metre LNG storage tanks, according to the presentation. The jetty will be able to berth a 80,000 tonne LNG tanker.
GEECL restores CNG supply in Bengal’s Durgapur-Asansol belt after gherao withdrawn
Coal-bed methane producer Great Eastern Energy Corp (GEECL) on Tuesday said it has normalised its gas supply in West Bengal’s Durgapur-Asansol belt after more than 60-hour-long gherao by agitators ended at its gas gathering station in the area. The CNG gas supply was suspended from Sunday for security and safety reasons after the agitation by some locals began at the unit on October 17. Around eight staffers were stuck inside the gas gathering station during the agitation, the company said. “The gherao had ended after more than 60 hours. The gas supply has been normalised and all safety measures are in place,” the company said. It was the third instance of gherao at the station in the last 43 days, it said. The trouble brewed at the unit after the termination of 29 third-party security men. “Twenty-nine third-party security men were terminated by the agency as per law due to severe and deliberate safety violations done by them,” the company said. “A group of miscreants have again done a gherao from the morning of October 17 and stopped the workers and staff from both entering and leaving the gas station,” GEECL had said on Monday.
China’s Guangzhou Gas says LNG import terminal to begin operations by H2 2022
China’s Guangzhou Gas Group said on Wednesday the liquefied natural gas (LNG) storage tank and jetty it’s building on the southern coast in Guangzhou is expected to begin commercial operation by second-half 2022, with initial annual throughput of 1 million tonnes. In slides presented at a gas conference in Shanghai, the company said it would begin issuing tenders to buy over 1 million tonnes per year of LNG for the medium and long term in 2021. Local government-backed Guangzhou Gas, one of China’s fast-growing players in the LNG sector outside the national state giants, had earlier planned to build a 2 million tonnes per year LNG terminal by 2020. Phase 1 of the terminal project on the southern coast includes building two 160,000 cubic metre LNG storage tanks, while Phase 2 includes building two 200,000 cubic metre LNG storage tanks, according to the presentation. The jetty will be able to berth a 80,000 tonne LNG tanker.
Natural gas exchange and growth of India’s gas sector
In June 2020, the announcement that a natural gas exchange would start functioning in India took us by surprise. The Government had announced its desire to set-up the exchange earlier and work on the regulatory design had been underway for more than two years. At the time of the announcement, the regulator had not published draft guidelines for setting up the exchange. Soon enough the exchange was indeed inaugurated on June 15, 2020., and has been operating thereafter. There are two primary drivers for setting up a natural gas exchange in India. The primary driver is the aspiration of the Indian policy makers to increase the share of natural gas in India’s primary mix from 6% to 15%. Due to past policies and formulae, India has multiple prices for natural gas (different for domestic and imported gas), even though the commodity is the same. Long term investment decisions underpinned on usage of natural gas, necessitates that there is one market-determined price for gas. There is a history of gas-based power plants and gas-based steel plants, becoming financially unviable with changes in availability of domestically produced gas. Therefore, for India to move towards higher gas usage, a spot-market for natural gas with the ability to hedge risks through derivatives is imperative. The second driver relates to incentivising domestic natural gas production. After the Supreme Court ruled in May 2010 that natural gas prices should be subject to Government control, the Indian upstream sector has been pushing for market determined prices, which was also the intent of the NELP contracts. Thereafter, under the HELP policy, the Government has reverted to providing pricing freedom. Price discovery through an exchange is a good transparent way of determining market prices. While these are still early days, the data suggests that volumes traded on the exchange are very limited. After the gas exchange started functioning, PNGRB issued draft guidelines for public comment. Most comments made by interested parties were on areas covered by the regulations e.g., settlement, margins for the exchange, capital requirements, etc. PNGRB has now finalised the regulations that would govern the natural gas exchange. However, policy makers would need to address some larger issues to make gas trading a success in India. One question is whether the exchange would impact the pricing of domestically produced natural gas. Currently, domestically produced gas is priced based on a formula which essentially determines the Indian gas price based on prices in gas surplus countries such as USA, UK, Russia and Canada. This provided an independent bench-mark to determine domestic gas which are reset every 6 months. However, since most of the benchmark countries have an oversupply of gas, this has ensured that India’s domestically produced gas is available for a low price (the recent price revision effective October 1, 2020 is at an all-time low of USD 1.79/mmbtu). The current domestic gas price formula does not address the investment & cost requirements to maintain and improve domestic production, as the Indian geology is higher risk with higher extraction costs for new discoveries . There is also the dichotomy of a large variance between domestic and imported gas prices. Imported gas is more expensive due to the capital-intensive LNG value-chain (liquefaction, shipping, re-gas etc). Domestic gas currently accounts for approximately 50% of gas consumption in India. Further, through the gas-allocation policy, the Government has prioritised sectors such as fertilisers and city gas. Given that domestically produced gas is cheaper than imported gas, there has been a queue of players wanting to source domestic gas. The Gas Exchange has a better probability of functioning like a perfectly competitive market only when there are large number of buyers and sellers. Besides giving depth, inclusion of domestic gas on the exchange will reduce also price volatility and reduce the demands on the Government to allocate cheaper gas. However, changing the basis for pricing of domestically-produced gas is not without its challenges. PSCs may need to be amended. Anybody who stands to lose i.e., beneficiaries of the gas allocation policy could protest and even litigate. Then there is the issue of the subsidy-bill of the Government. It will not be an easy decision. Also, sufficient pipeline network capacity and pipeline access needs to provided to buyers and sellers of gas on a non-discretionary basis. The gas-trading guidelines do provide for the buyer or the exchange to have a gas transportation agreement. However, the larger question is whether carriage and selling of gas should be totally separated or pipelines should continue to operate on the basis of third-party access for part of the pipeline capacity. Separation of transportation and marketing has worked very well in the largest gas market – USA. For India to increase the share of gas in its primary energy mix, new pipelines would be required. Pure transportation pipelines i.e., where the transporter cannot be a seller of gas may require financial support from the Government. The volumes to underpin the development of new pipelines are not there, when investment decisions are made. It is a chicken and egg story between demand and supply. Therefore, in the past, building of pipeline infrastructure has been incentivised by allowing the pipeline companies to also sell gas. Without bundling transportation and selling gas, the gas volumes may not justify the investment decision. Consequently, incentivisation for building new pipelines may be at variance vis-à-vis an effective exchange for natural gas for which total unbundling would be the preferred option. Finally, natural gas is outside the purview of GST and is subject to state VAT. If India wants an integrated gas-based economy, then natural gas must be brought under the purview of GST. GST was implemented by the Centre agreeing to underwrite an annual 14% growth in the State Government’s tax revenues subsumed by GST. Even before the onset of COVID, Government was unable to bring natural gas under GST. Collapse in the revenues of both the State and the Central Governments and the issue of compensation of states for shortfall in GST
Dharmendra Pradhan launches trial run of Delhi’s buses on Hydrogen-blended CNG
Union Minister of Petroleum & Natural Gas and Steel Dharmendra Pradhan inaugurated Indian Oil’s compact reformer plant and launched the much-awaited trial run of Delhi’s buses on Hydrogen-blended CNG (HCNG) at the Rajghat Bus Depot-I of Delhi Transport Corporation (DTC) on Tuesday. Speaking on the occasion, Pradhan said that providing clean and reliable energy supplies to 130-crore plus Indians is the topmost priority of the Government. “I am happy to note that the scientists of Indian Oil R&D have risen to the occasion and have developed an innovative compact reforming technology for production of Hydrogen-mixed CNG,” he said. Elaborating on the importance of Hydrogen in facilitating India’s energy transformation, the Minister said that Hydrogen is the ultimate fuel, which, while giving energy, produces clean water in the emissions. “Apart from this, it has many other virtues as the capacity to get the rural sector involved with the energy sector through biomass. This pilot project will be unique. It will help the county and the world as a whole,” he stated. Kailash Gahlot, Minister of Transport, Government of Delhi, was also present on occasion.
Govt bans sale of gas, CBM to self
The government has banned natural gas and coal-bed methane (CBM) producers from buying their own produce in the newly notified gas marketing freedom guidelines. The government on October 15 notified the Natural Gas Marketing Reforms that give producers the freedom to discover the market price of gas through a standard e-bidding process. The notification, which follows the Cabinet Committee on Economic Affairs approving gas reforms, also gives them the liberty to market or sell the gas produced to anyone including affiliates. However, the producer or any member of its gas field consortium cannot bid and buy the fuel, the notified guidelines said. “Sale to affiliates will be allowed if affiliates participate in the open competitive process,” it said. “However, the contractor or its constituents shall not be eligible to participate in the bidding process.” “Seller and buyer will not be the same entity,” it added. This, the notification said, not just applies to conventional natural gas but also to CBM. In 2017, Reliance Industries had bid and bought all the gas it was producing from its Sohagpur East and Sohagpur West CBM blocks in Madhya Pradesh. The company used the gas at its petrochemical plants in Patalganga and Nagothane in Maharashtra, and Vadodara and Jamnagar in Gujarat. Reliance had outbid gas utility GAIL India Ltd for gas from Sohagpur till March 2021. State-owned GAIL had criticized the move saying Reliance had a 14 per cent tax advantage in the bid as stock transfer within the company is not subject to VAT. The Oil Ministry had subsequently sought an explanation from Reliance which reasoned the sale to the CBM contract providing marketing freedom and the gas being sold through “an open and transparent bidding process through a reputed independent third party in compliance with provisions of the CBM contract and policy.” To put the ambiguity to rest, the October 15 notification said with the new change “the April 11, 2017 notification on Early Monetization of CBM, regarding the process of the sale, will stand amended.” The new guideline provides for the contractor selling the natural gas through e-bidding. “The contractor shall get the bids invited through an electronic bidding portal to discover market price by following a transparent and competitive bidding process notified by the government,” it said. The bidding will be conducted through an independent agency from a panel maintained by the Directorate General of Hydrocarbons (DGH). DGH is currently in the process of empanelling such agencies. “Marketing freedom is granted for natural gas produced from Field Development Plans (FDPs) which were approved before February 28, 2019 pertaining to Production Sharing Contracts (PSCs), where Contractor has pricing freedom but market freedom is restricted,” the notification said. The market price of such gas shall be discovered through e-bidding, it said. “This policy will not apply to those contracts/PSCs where the contractor is required to get the formula or basis of sale approved from the Government or the contractor is required to sell the gas as per the specific conditions of the contract,” it said. This essentially meant the gas produced by state-owned Oil and Natural Gas Corp (ONGC) and Oil India Ltd (OIL) from fields given to them on a nomination basis would continue to be governed by government-dictated price, which currently is USD 1.79 per million British thermal unit. Also, fields like Ravva in the KG Basis which are governed by a formula in the contract would be out of this policy’s purview.
Facing wave of closures, oil refiners turn to biofuels
European and U.S. oil refineries face a wave of closures due to plateauing fuel demand, tightening environmental rules and overseas competition, prompting some owners to opt for an easier alternative – converting plants to produce biofuels. The shock of the coronavirus epidemic crushed global oil demand and as some producers, including BP, say it might never recover to pre-crisis levels, the need to close refineries has accelerated. The International Energy Agency (IEA) said in a recent report that by 2030 around 14per cent of current refining capacity in advanced economies “faces the risk of lower utilisation or closure.” That share could grow to 50per cent in 2040 under a more aggressive transition away from fossil fuels to electric vehicles, the IEA said. Shutting down refineries, some of which are 70 years old, is a costly process which requires dismantling heavy equipment and pipelines and remediating the land. So owners are choosing alternative paths, including converting refinery sites to import terminals, putting them to other industrial uses or, in many cases, switching to cleaner biofuels by processing vegetable oil and waste oils. BP, Total and Eni, outlined in recent months plans to grow their biofuel capacities by two to five fold by 2030 while reducing their global oil refining footprints. The switch is part of companies’ strategies to radically reshape and grow renewables and low-carbon businesses. Other European refiners including Repsol and independent Italian refiner Saras also plan to increase their capacity. Converting refineries to biofuels “makes a lot of sense,” said Rob Turner, partner at PWC specializing in the energy sector. “It allows plans to play a role in the energy transition, creates long-term value and mitigates the costs of a full shutdown and site cleanup.” Although refiners in other developed economies face a similar challenge, it is particularly difficult for Europe where local consumption has been in a steady decline and governments have accelerated efforts to curb carbon emissions. Already, three refineries in Europe have shut down in the wake of the coronavirus epidemic – Total’s Grandpuits plant in northern France, Neste’s Naantali plant in Finland and Gunvor’s Antwerp refinery. Total converted the La Mede refinery in southern France into a biodiesel plant in 2019. Other refiners, whose profits have collapsed due to a sharp drop in demand due to the epidemic, are on the brink. Europe’s biofuel production capacity is expected to grow to around 8 million tonnes per year from the current 3 million tonnes per annum, according to Barclays analyst Joshua Stone. Finnish refiner Neste Oyj, which has invested heavily in renewables and has biofuel facilities in Europe and Singapore, has seen its shares soar in recent months while those of traditional refiners and energy companies dropped. Neste’s shares have gained over 55per cent so far this year while shares of Saras have tumbled 69per cent. COMPETITION In the United States, demand for biofuel is also set to grow rapidly in the coming years due to new fuel quality regulations in states including California. It is set to reach 2 billion gallons per year by 2025 from 21.4 million gallons currently consumed every year, according to Morgan Stanley. There are currently eight projects totalling over 1.1 billion gallons per year of capacity being constructed with targeted completion dates in the next five years. Refiners including Phillips 66 and HollyFrontier Corp have also announced plans to ramp up production. The gap between demand and supply in the United States could lead to a supply shortfall of about 450 million gallons per year, meaning it will need to import biofuels, Morgan Stanley said. With biofuel demand growing sharply on both sides of the Atlantic, prices for feedstock – vegetable oil and oil produced from waste – will likely increase. “An increase of raw material prices is inevitable over the period with so many new biofuel facilities competing for similar sources of feedstock,” Barclays’ Stone said. Profit margins for producing biodiesel will likely erode as a result but are expected to remain robust due to strong demand and their very high starting point at the moment, he said.
Japanese sell out of Australian LNG import project
Australian billionaire Andrew Forrest has taken over full control of a A$250 million ($176 million) gas import terminal in New South Wales, buying out stakes held by Japan’s JERA and Marubeni Corp in a push to speed up the project. Squadron Energy, privately owned by mining magnate Forrest, said on Tuesday it acquired 30.1 per cent of Australian Industrial Energy (AIE) from trading house Marubeni and 19.9 per cent from JERA for an undisclosed price. The deal sees Squadron take full control of the Port Kembla Gas Terminal project that AIE is developing. “Squadron Energy is committed to the expedited development of the gas import terminal with the objective of having the capacity to supply 70 per cent of NSW’s gas needs by late 2022,” Squadron said. JERA, owned by Tokyo Electric Power and Chubu Electric Power, said the liquefied natural gas (LNG) import terminal made sense for a region that faced tight gas supply. “However in our process of selecting and concentrating on business investment projects, we decided to withdraw as a result of a comprehensive internal review,” JERA said in an emailed comment. The company last week set out plans to achieve net zero emissions of carbon dioxide by 2050 to tackle climate change. Marubeni declined to comment. In the Squadron statement, Chairman Michael Masterman said JERA, the world’s biggest LNG buyer, and Marubeni have indicated they would be open to working with AIE in the future, including lining up LNG supplies and building an associated gas-fired power station. AIE has been pushing to reach a final investment decision on the Port Kembla project this year, in order to start importing LNG by 2022, with construction expected to take 14 to 16 months. The project is one of five aiming to import LNG into southeast Australia to fill a looming shortage expected from 2024 as gas supply from the Bass Strait fields off the coast of Victoria rapidly declines.