Gas price for Reliance to be reduced by 14% from next month
The price of natural gas produced from difficult areas like KG-D6 of Reliance Industries is likely to be cut by about 14 per cent from next month in line with softening energy prices, sources said. For the six-month period starting October 1, the price of gas from deep-sea and high-pressure, high-temperature (HPTP) areas is likely to be cut to around USD 10.4 per million British thermal unit from the current USD 12.12, they said. The government bi-annually fixes prices of the locally-produced natural gas — which is converted into CNG for use in automobiles, piped to household kitchens for cooking and used to generate electricity and make fertilizers. Two different formulas govern rates paid for gas produced from legacy or old fields of national oil companies like Oil and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL), and for newer fields lying in difficult-to-tap areas, such as deep-sea. Rates are fixed on April 1 and October 1 each year. In April this year, the formula governing legacy fields was changed and indexed to 10 per cent of the prevailing Brent crude oil price. The rate was however capped at USD 6.5 per mmBtu. Rates for legacy fields are now decided on a monthly basis. For September, the price came to USD 8.60 per mmBtu but because of the cap, the producers would get only USD 6.5. Brent crude oil has averaged around USD 94 per barrel this month but rates will continue to be capped at USD 6.5. Sources said the price for difficult area gas continues to be governed by the old formula that takes one-year average of international LNG prices and rates at some global gas hubs with a lag of one quarter. International prices had fallen in the reference period of July 2022 to June 2023 and so it will translate into lower prices for difficult fields, they said. The price for gas from difficult fields was cut to USD 12.12 per mmBtu for a month period, beginning April 1 from a record USD 12.46 earlier. The global spurt in energy prices after Russia’s invasion of Ukraine has led to rates of locally-produced gas climbing to record levels – USD 8.57 per million British thermal unit for gas from legacy or old fields and USD 12.46 per mmBtu for gas from difficult fields between October 2022 and March 2023. On April 1, prices of gas from legacy fields were slated to climb to USD 10.7 per mmBtu using the old formula. But the government changed the formula and put a cap to keep inflation under check. Rates of CNG and piped gas for kitchens had risen by 70 per cent because of the previous gas price hike. The ceiling price covers the cost of production of producers while protecting consumers, particularly CNG users, kitchens using piped cooking gas and fertiliser plants which had grappled with soaring input costs. India is aiming to become a gas-based economy with the share of natural gas in its primary energy mix targeted to rise to 15 per cent by 2030 from the existing level of around 6.3 per cent.
Strong Crude Draw, Falling Inventories At Cushing Support Oil Prices
The American Petroleum Institute (API) has reported a large 5.25-million-barrel draw in U.S. crude inventories, offsetting last week’s 1.174-million-barrel build. Analysts were expecting an inventory draw of 2.667 million barrels for the week. The total number of barrels of crude oil moves so far this year is now squarely in the red, according to API data, and there is a net draw in crude inventories since April of more than 52 million barrels. On Monday, the Department of Energy (DoE) reported that crude oil inventories in the Strategic Petroleum Reserve (SPR) rose by 600,000 barrels last week, with the SPR inventory still sitting at a near 40-year low of 351.2 million barrels. The amount being purchased to put back into the SPR is a small portion of the hundreds of millions of barrels that were sold off out of the SPR over the last couple of years. Oil prices were trading up on Tuesday ahead of API data release, with Brent trading up 0.23% at $94.65 at 4:11 p.m. ET—a $2.50 gain week over week, while WTI was trading up 0.15%, at $91.62 per barrel—a gain of more than $2.50 per barrel from this time last week. Gasoline inventories saw the only rise this week, by 732,000 barrels, on top of the 4.21 million barrel build in the week prior. Gasoline inventories are roughly 2% less than the five-year average for this time of year. Distillate inventories fell by 258,000 barrels, partially offsetting the 2.592-million barrel build in the week prior, and are 13% below the five-year average for this time of year. Cushing inventories fell by another large 2.564 million barrels after falling 2.417 million barrels last week, leaving just over 22 million barrels in Cushing.
Will oil price hit $100 amid relentless rally? It already did in some markets
With oil investors and traders focused on an oil-price rally that has come close to $100 a barrel, some grades of crude oil are already trading above that milestone, highlighting an expectation of tight supply. The outright price of Nigerian crude Qua Iboe surpassed $100 a barrel on Monday, according to LSEG data. Malaysian crude Tapis reached $101.30 last week, said Bjarne Schieldrop, analyst at Swedish bank SEB, in a report. Oil has risen to its highest level of 2023 as investors are focused on the prospect of a supply deficit in the fourth quarter after Saudi Arabia and Russia extended supply cuts. The two are the biggest producers in the OPEC+ group, most other members of which are also curbing output. “The overall situation is that Saudi Arabia and Russia are in solid control of the oil market,” Schieldrop said. Brent oil futures, a global benchmark, traded as high as $94.89 on Monday and the related benchmark used for trading much of the world’s physical cargoes, called dated Brent stood just above $96 according to LSEG. Qua Iboe, and some other crudes priced against Brent, are above $100 already because they are based on the price of dated Brent plus a cash differential or premium, currently assessed by LSEG at around $4.25 a barrel. Schieldrop said dated Brent is highly likely to move above $100 as “only noise is needed to bring it above.” Swiss bank UBS sees Brent futures reaching triple digits. “We expect Brent to trade in a range of $90–100 over the coming months, with a year-end target of $95,” said UBS analyst Giovanni Staunovo.
EIA Forecasts Continued Decline In U.S. Shale Oil Output
Shale oil production in the United States is set to decline for the third month in a row to 9.39 million barrels daily, the Energy Information Administration said in its latest Drilling Productivity Report. That would be down from 9.433 million barrels daily for August and a record-high 9.476 million bpd for July. Most of the decline would come from the Permian basin—the star of the shale patch. There, the EIA has projected a production decline of 26,000 bpd, followed by a 17,000-bpd output drop in the Eagle Ford basin. Reuters noted in a report that the decline this month would be the biggest negative monthly change since December last year. Even so, the EIA remains certain total U.S. oil production will hit a record this year and another one in 2024. The agency has the same forecast for natural gas production. For this year, the EIA last month said it saw production hit 12.76 million bpd, which would be an increase of 850,000 bpd on the 2022 average. In 2024, the EIA sees output rising by another 330,000 bpd to 13.09 million bpd. Yet the rig count has been falling for much of the year and despite a recent reversal of the decline trend, the total rig count remains 16% below the levels it was this time last year, per Baker Hughes data. That said, some shale producers have recently reported higher well productivity thanks to greater drilling efficiency. This increased productivity, however, has not been enough to keep prices in check. West Texas Intermediate is currently trading at over $92 per barrel, pushing retail fuel prices higher, too. Yet even if producers decide to respond to higher prices with more drilling, it would take time to see the increased drilling—if it materializes—translate into lower crude and fuel prices.
Pipelines Are Limiting U.S. Natural Gas Production
In its latest biennial assessment delivered last week, the Potential Gas Committee (PGC) reported that U.S. natural gas supply has hit a record 3,978 trillion cubic feet, good for a 3.6% increase from the 2020 estimate with shale gas dominating supply at 61%. The country’s technically recoverable resources, however, fell slightly by 0.5% to 3,352 Tcf likely due to some volumes being shifted to other categories. The Atlantic region, home to the gas powerhouse Marcellus and Utica shale plays, harbors the lion’s share of supplies at 40% of estimated gas resources. More than 800 volunteer geoscientists and engineers contributed to PGC’s assessments. Unfortunately, unlocking that deluge of gas might be limited by the availability of one critical infrastructure: gas pipelines. “Future gas supplies continue to increase as the energy industry innovates, improves processes, optimizes resources, invests in efficiency and reduces emissions. However, to fully realize the potential of this natural gas supply, new infrastructure will be required to connect production zones to demand centers,” Richard Meyer, the American Gas Association’s vice president of energy markets, analysis and standards, has said. It’s a viewpoint buttressed by PGC President Kristin Carter, “The availability of pipelines to get the product out of the shale gas fields in particular–there’s only so much they can get to market without more of that infrastructure. So for that reason, you might have inactive wells.” ‘Pipeline constraints’ is becoming an increasingly common refrain. Over the years, environmental groups In the Appalachian Basin, the country’s largest gas-producing region churning out more than 35 Bcf/d, have repeatedly stopped or slowed down pipeline projects. This has left the Permian Basin and Haynesville Shale as the regions doing much of the heavy lifting when it comes to growing LNG exports. Indeed, last year, EQT Corp.(NYSE: EQT) CEO Toby Rice acknowledged that Appalachian pipeline capacity has “hit a wall.” Analysts at East Daley Capital Inc. have projected that U.S. LNG exports will double by 2030 from their current level of ~13 Bcf/d. But for this to happen, the analysts estimate that another 2-4 Bcf/d of takeaway capacity needs to come online between 2026 and 2030 in the Haynesville. “This assumes significant gas growth from the Permian and other associated gas plays. Any view where oil prices take enough of a dip to slow that activity in the Permian and you’re going to have even more of a call for gas from gassier basins,” the analysts have said. LNG Expansion The construction of new export terminals has rapidly increased U.S. LNG exports every year since 2016, making the country one of the top three LNG-exporting countries in the world. The U.S. Energy Information Administration (EIA) has forecast that U.S. LNG exports will continue to grow in 2024, as two LNG projects come online: Golden Pass in Texas and Plaquemines in Louisiana. Golden Pass Trains 1 and 2 projects is a joint venture between ExxonMobil Corp.(NYSE:XOM) and QatarGas. They are being built at an existing LNG import terminal in Texas that will be converted into an LNG export facility consisting of three trains, each with 0.68 Bcf/d of nominal capacity, or 0.80 Bcf/d of peak capacity. According to filings with the Federal Energy Regulatory Commission (FERC), Trains 1 and 2 will come into service during the second and fourth quarters of 2024, respectively while Train 3 will come online in the first quarter of 2025. Meanwhile, Plaquemines LNG Phase 1 is a Venture Global project located in Louisiana. Phase 1 consists of 9 blocks, each containing 2 liquefaction trains for a total of 18 liquefaction trains with a combined nominal capacity of 1.3 Bcf/d, or peak capacity of 1.6 Bcf/d. According to FERC filings, developers plan to bring Phase 1 online by the end of 2024 and expect to start LNG production in August 2024. EIA has projected that Golden Pass Trains 1 and 2 and Plaquemines Phase 1 will add a total of 2.7 Bcf/d of nominal LNG export capacity, or 3.2 Bcf/d of peak capacity with nominal liquefaction capacity increasing to 14.1 Bcf/d and peak capacity to 17.0 Bcf/d across the nine U.S. LNG export facilities by the en EIA notes that current international natural gas market conditions are conducive for expanding U.S. LNG exports, with natural gas prices in Europe and Asia relatively high compared with U.S. natural gas prices. Meanwhile, relatively little growth in global LNG export capacity is expected in the next two years thus increasing demand for flexible LNG supplies, mainly from the United States. The energy watchdog has estimated that U.S. LNG exports will average 12.0 billion cubic feet per day (Bcf/d) in the current year and increase to 13.3 Bcf/d in 2024. EIA has predicted that U.S. LNG exporters will use 105% of nominal capacity in 2023 and 108% in 2024, utilization levels equivalent to 88% and 90% of peak capacity in those years.
LNG Market Grows More Mature, But Supply Risks Remain
European gas prices spiked earlier this month as workers at three LNG facilities in Australia threatened industrial action. Strikes were avoided at one of the facilities, but the danger remained for the other two, keeping a floor under gas prices. But over the past year, attempts have been made to put a sort of a ceiling on gas prices in Europe—and more specifically, LNG prices. The effort is beginning to pay off. Until last year, the global LNG market featured long-term contracts indexed to crude oil futures prices, and spot deals. After Russia invaded Ukraine, the EU started shooting sanctions, and pipeline gas flows began to shrink, LNG suddenly became extremely important for Europe. And that prompted a race to lower the pricing risks associated with the state of the LNG market at the time. That race resulted in the launch of the Northwest European LNG futures contract based on the S&P Global NWM, or Northwest Marker. The LNG market matured fast. Traders in an extremely volatile market could hedge European LNG cargos. They could also no longer care so much about pipeline gas and its price when trading LNG. The reason, once again, was the market disruption caused by the Ukraine conflict, chief among them the decimation of gas flows from Russia, especially after the sabotage of the Nord Stream pipeline. A mature market is a lower-risk market, and this is what has been happening to the LNG market over the past year and a half. This, however, has not really reduced the extent of volatility in that market, as evidenced by the effect that news of the potential strikes at Australia’s top three LNG facilities had on LNG prices, especially in Europe. Hedging is important in trade, but when there is a danger of a supply shortage, all bets are off. And there was a danger of a supply shortage equal to a tenth of total global supply—this is how much the North West Shelf, Gorgon, and Wheatstone produce together. Ultimately, supply and demand continue to trump any other factors traders might use to reduce risks inherent in commodity markets. No doubt, it is good to have a liquid market, and now, thanks to the rise of the Dutch benchmark TTF at the expense of the UK’s National Balancing Point, LNG traders have such a liquid market. Trade is more active than ever and easier than ever, even intercontinental trade with Asia. At the same time, however, prices, whatever benchmark they are based on, remain supersensitive to the threat of potential outages. The good news is that perhaps a repeat of last year’s price spikes may be less likely this year or in the future because of the maturing LNG market. On the other hand, tight supply, in case of a cold Northern Hemisphere winter, could push prices significantly higher during peak demand season. The good news, for now, is that Europe’s gas storage is fuller than usual for this time of the year. Thanks to leftover volumes from last year, which were bought at record prices, and it made no sense to resell them at a huge loss, the continent’s storage is now 92.5% full. This could provide a comfortable buffer in case of an outage, especially if the outage does not last very long. Even with this buffer, however, Europe will continue to be a major rival for Asia in LNG cargos as it has been forced to reduce its reliance on pipeline gas. Demand from Asia is already picking up ahead of the winter season. This season will probably be the first big trial for the new, more mature, global LNG market.
Turkmenistan’s Natural Gas Boom Sparks European Interest
Turkmenistan’s huge gas reserves have been generating considerable interest from potential importers following Ashgabat’s announcement in late July that it is open to the development of a pipeline to carry its gas across the Caspian and on to Europe. Most significant so far has been the interest shown by Hungary, which on August 20 signed a framework gas supply agreement with Turkmenistan, during a state visit to Budapest by Turkmen President Serdar Berdymukhamedov. Also in Budapest for meetings with Hungarian leader Viktor Orban were Turkish President Recep Tayyip Erdogan – who was there to oversee the signing of a gas supply agreement between Turkey’s state gas import-export and transit company Botas and Hungary’s state power company MVM for 300 million cubic metres a year of gas – and Azerbaijani President Ilham Aliyev, whose state oil company SOCAR is already supplying MVM with 1 billion cubic metres a year of Azerbaijani gas. For Hungary and the EU, these three agreements are significant as they signal that the central European state is preparing for a future without guaranteed gas supplies from Russia, which is currently Hungary’s main supplier and with which Budapest continues to enjoy cordial relations. However, flows of Russian gas, which arrive via Ukraine are set to stop by the end of 2024 with Kyiv having signalled its unwillingness to renew the existing transit agreement with Moscow – an understandable move given Russia’s ongoing invasion. For Turkmenistan, the agreement is the most concrete evidence so far that Europe is serious about receiving gas from Turkmenistan’s vast reserves in place of Russian gas, imports of which have all but halted since Russia’s invasion of Ukraine early last year. How much Turkmen gas Hungary will import, how the gas will be delivered, and when supply will commence, have not been made clear. With no pipeline yet developed to carry gas from Turkmenistan across the Caspian, the only route currently open would be via the three-way gas swap deal between Turkmenistan, Iran and Azerbaijan first agreed in late 2021, and recently expanded. Under that agreement Turkmenistan sends its own gas to northeastern Iran, which then transits the same volume of its own gas on to Azerbaijan, enabling Baku to meet its own growing gas demand and existing gas export agreements while freeing up further volumes of Azerbaijani gas for onward transit to Europe. Although cumbersome, the three-way swap has been operating successfully since January last year and was recently expanded from 4.5 million cu m/day to 8 million cu m/day with plans to expand it further to 10 million cu m/day. Gas sold by Turkmenistan could be transited from Azerbaijan using spare capacity in the three pipelines which make up the Southern Gas Corridor that currently carries Azerbaijani gas to Georgia, Turkey and on to Europe. In July last year, Azerbaijan signed a memorandum of understanding with the European Union under which it undertook to double the volume of gas it sends to Europe to “at least 20 billion cu m/yr” by 2007. However, it is still unclear whether Azerbaijan will be able to double its own gas production by then, with the Turkmen-Iran swap agreement currently the most likely source of gas to fill any gap. Iran stands to also be the route to another gas-hungry market interested in importing Turkmen gas, namely Iraq. The oil-rich Middle Eastern state also has large gas reserves of its own but decades of political instability and the high cost of developing the fields have so far prevented the investment necessary to bring them to market. Baghdad has for some years been importing gas from Iran to generate electricity, but maintaining steady supplies has been difficult due to difficulties transferring payment caused by the ongoing US sanctions against the Islamic Republic, as well as Iran’s own periodic problems meeting domestic demand. A preliminary agreement between Baghdad and Ashgabat signed on August 24 is expected to be followed by the end of this year with a formal agreement detailing volumes and transit details, which are expected to involve some form of barter arrangement which will avoid the necessity of transferring money to Tehran. Turkey and Azerbaijan key to bringing Turkmen gas to market Swap deals transferring gas via Iran are feasible for the small volumes of gas expected to be involved in agreements with Hungary and Iraq. But with gas reserves estimated at between 10 and 14 trillion cubic metres, the main focus of interest in Turkmenistan remains its potential to replace the Russian gas that has all but stopped flowing to Europe since Russia’s invasion of Ukraine. Any significant gas transit from Turkmenistan will require the development of a whole new pipeline infrastructure crossing the Caspian Sea and running through Azerbaijan, Georgia Turkey and the Balkans to connect with the existing central European pipeline network which, with no Russian gas, has the necessary spare capacity. Azerbaijan has already signalled its interest in hosting such a transit line but has warned it is unwilling to bear any of the cost. Turkey too has frequently signalled interest in transiting Turkmen gas to Europe. In May Ankara issued a new 10-year import license to state gas importer Botas, for the import of up to 16 billion cu m/yr of Turkmen gas under a contract signed in the late 1990s, but never implemented it due to the lack of a pipeline. Whether the development of such a pipeline is getting any closer is the subject of considerable interest in Europe. Certainly, the presence of Turkmen President Serdar Berdymukhamedov, Turkish President Tayyip Erdogan and Azerbaijani President Ilham Aliyev, all in Budapest at the same time provided the opportunity for high-level talks. An opportunity noted by Hungarian president Viktor Orban who, referring to his visitors, posted on X, “That’s what I call connectivity.”
Evading primary responsibility, ONGC decides to invest Rs 150 billion in sick subsidiary
It is reported that Oil and Natural Gas Corporation (ONGC) will infuse about Rs 150 billion in ONGC Petro-additions Ltd (OPaL) as part of a financial restructuring exercise. ONGC currently holds 49.36 per cent stake in (OPaL), which operates a mega petrochemical plant at Dahej in Gujarat. GAIL (India) Ltd has 49.21 per cent interest and Gujarat State Petrochemical Corporation (GSPC) has the remaining 1.43 per cent. OPaL is reported to have incurred losses in the past due to lopsided capital structure with high-debt servicing cost. It is said that cost overrun due to delay in implementation of project is the primary reason for it incurring losses . Obviously, delay in implementation and commissioning of the project must have happened due to various reasons and perhaps, including some hidden reasons which have not been shared adequately. Accumulated losses touched Rs 130 billion on 31st March 2023. As noted by the company’s auditors, OPaL is “facing negative working capital of Rs 70.750 billion as of that date. Net worth of the Company has reduced to Rs 6,207.99 million as at March 31, 2023 as compared to Rs 45,837.20 million as at March 31, 2022. In spite of these events or conditions which may cast doubt on the ability of the company to continue as a going concern, the management is of the opinion that going concern basis of accounting is appropriate in view of the cash flow forecasts and the plant management has put in place along with other facts.” ONGC’s proposal It is reported that ONGC would make additional investment that would convert Opal into virtually a subsidiary of ONGC. While ONGC would spend Rs 150 billion in OPaL, there is no information in the public domain as to what would be the strategy to revamp the unit and place it on the path of profitability. This information is particularly necessary, since the product range of OPaL are extremely important and apparently there are no technical snags in operating the projects. Mere change of product mix by OPaL as part of revamping plan will not provide any significant reduction in loss.
Italy’s Eni looks to sell LNG in Southeast Asia, may introduce US LNG into portfolio
Italy’s Eni is looking to sell LNG into Southeast Asia to tap new emerging buyers and it may also consider introducing more US LNG into its portfolio to diversify its volumes, Cristian Signoretto, deputy chief operating officer natural resources and director global gas & LNG portfolio, told S&P Global Commodity Insights in an interview. There is a lot of potential demand in Southeast Asia due to a number of reasons — floating regasification technology has made it much easier to get access to LNG compared to an onshore facility that would cost more and take very long to build; and the countries have to substitute coal with gas in order to reduce the use of polluting fuels, he said. “So they are coming into the market. And this is a good niche opportunity for portfolio players and producers. We are actively marketing our volumes in those countries,” Signoretto said. While Southeast Asian demand is much lower than South Korea, Japan or China, the region opens up multiple opportunities, he said. “So this is definitely a trend that is expected to increase.” Signoretto said emerging buyers usually have national utilities that provide sovereign guarantees which helps facilitate transactions, although the smaller energy players can be more of a headache, when asked about the challenge of dealing with new buyers with low credit worthiness. “With LNG you can take a bit more risk [compared to pipelines] in the sense that if for some reason the counterparty does not honor the contract, you still can move the LNG somewhere else,” he added. Signoretto also said India is a very cautious buyer of gas as the right price is needed to displace other fuels in the country, and at around $15-$16/MMBtu, the country refrains from buying LNG because it’s too expensive. “They can use other fuels,” he said. Meanwhile, China’s heating demand is a bit inflexible and inelastic because heating systems are switched to gas, its tough to go back to fuel oil or coal, he said. China is increasing the penetration of gas in industrial and power sectors, but they also have access to other sources like piped gas from Russia and Central Asia, although the country has a slightly higher price tolerance for LNG, Signoretto said. Eni has plans to expand its contracted LNG portfolio to over 18 million mt/year by 2026, from around 10 million mt/year, which will help replace around 20 billion cubic meters of lost Russian gas by 2025. Most of this is expected to come from equity projects in Congo, Mozambique, Nigeria and Qatar. In Mozambique, Eni recently developed the Coral Sul floating LNG project and the company is now working on a second floating LNG project in the country, Signoretto said.
Diesel sales fall in September amid rains, petrol consumption up in India
Diesel sales in India fell for the second straight month in September as rains dampened demand and slowed industrial activity in some parts of the country, preliminary data of state-owned firms showed. While diesel sales by three state-owned fuel retailers fell year-on-year in the first half of September, petrol sales were up marginally. Consumption of diesel, the most consumed fuel in the country accounting for about two-fifths of the demand, fell 5.8 per cent to 2.72 million tonnes between September 1 and 15, compared to the year-ago period. Consumption had fallen by a similar proportion in the first half of August. Month-on-month sales were up 0.9 per cent, when compared with 2.7 million tonnes of diesel consumed in the first half of August. Diesel sales typically fall in monsoon months as rains lower demand in the agriculture sector which uses the fuel for irrigation, harvesting and transportation. Also, rains slow vehicular movements. Consumption of diesel had soared 6.7 per cent and 9.3 per cent in April and May, respectively as agriculture demand picked up and cars yanked up air-conditioning to beat the summer heat. It started to taper in the second half of June after the monsoon set in. It fell in the first half of July but picked up in the second fortnight of that month. Petrol sales were up 1.2 per cent to 1.3 million tonnes in the first fortnight of September, when compared with the same period last year.