Everyone wants a pie of India’s largest renewable power producer
French energy giant TotalEnergies SE’s USD 300 million investment in clean energy projects of Adani Green Energy Ltd has taken the total investments poured in by global investors in India’s largest renewable power producer to USD 1.63 billion or about Rs 140 billion, sources close to the company said. Last week, Total announced it will hold a 50 per cent stake in the new joint venture firm where Adani Green Energy Ltd (AGEL) will hold the rest. The joint venture will hold a portfolio of 1,050 MW, including 300 MW of already operational capacity, 500 MW under construction and 250 MW under-development assets with a blend of solar and wind power. Total already has a 19.7 per cent stake in AGEL. It also has an equal joint venture with AGEL, called AGE23L that holds a portfolio of 2,353 MW. The USD 300 million investment Total is making in the joint venture is the first since the Hindenburg report in January highlighted Adani Group’s debt pile and alleged accounting fraud and stock manipulation, which Adani denies. Sources said AGEL is one company within the Adani Portfolio, which has attracted a range of investors over the past few months including repeat strategic investor Total, one of the largest emerging market funds GQG Capital Partners and one of the world’s largest sovereign funds Qatar Investment Authority. Together these three investors have invested USD 1.63 billion or close to Rs 140 billion over the past few months, taking advantage of the attractive valuations post the short-seller report, they said.
Oil prices rise as supply concerns outweigh demand fears
Oil prices rose on Friday as concerns that a Russian ban on fuel exports could tighten global oil supply outweighed fears that further possible U.S. interest rate hikes could dent fuel demand, but they were still headed for a weekly loss in four. Brent futures for climbed 21 cents, or 0.2%, to $93.51 a barrel by 0103 GMT, while U.S. West Texas Intermediate crude (WTI) futures gained 23 cents, or 0.3%, to $89.86. Both benchmarks were on track for a small weekly drop after gaining more than 10% in the previous three weeks amid concerns about tight global supply as the Organization of the Petroleum Exporting Countries and allies (OPEC+) maintain production cuts. “Trading remained choppy amid a tug-of-war between supply fears that were reinforced by a Russian ban on fuel exports and worries over slower demand due to tighter monetary policies in the United States and Europe,” said Toshitaka Tazawa, an analyst at Fujitomi Securities Co Ltd. “Going forward, investors will focus on whether the OPEC+ production cuts are being implemented as promised and whether the rise in interest rates will reduce demand,” he said, predicting WTI to trade in a range of around $90-$95. Russia temporarily banned exports of gasoline and diesel to all countries outside a circle of four ex-Soviet states with immediate effect to stabilise the domestic fuel market, the government said on Thursday. The shortfall, which will force Russia’s fuel buyers to shop elsewhere, caused heating oil futures Hoc1 to rise by nearly 5% on Thursday. The U.S. Federal Reserve on Wednesday maintained interest rates, but stiffened its hawkish stance, projecting a quarter-percentage-point increase to 5.50-5.75% by year-end. That buoyed fears that higher rates could dampen economic growth and fuel demand while boosting the U.S. dollar to its highest since early March, making oil and other commodities more expensive for buyers using other currencies. The Bank of England mirrored the Fed and held interest rates on Thursday after a long run of hikes, but said it was not taking a recent fall in inflation for granted.
India’s LNG imports rose in August
India’s liquefied natural gas (LNG) imports rose in August compared to the same month last year, according to the preliminary data from the oil ministry’s Petroleum Planning and Analysis Cell. The country imported 2.23 billion cubic meters, or about 1.7 million tonnes of LNG, in August, a rise of 10.1 percent compared to the same month in 2022, PPAC said. During April-August, India took 12.21 bcm of LNG, or some 9.3 million tonnes, up by 3.5 percent, PPAC said. India paid $1.3 billion for August LNG imports, down from $1.5 billion last year, while costs dropped from $8 billion in the April-August period last year to $6 billion during the same five months this year, it said. As per India’s natural gas production, it reached 3.16 bcm, up by 9.3 percent compared to the corresponding month of the previous year. During April-August, gas production rose by 3.6 percent to 14.85 bcm, PPAC said. At the moment, India imports LNG via seven facilities with a combined capacity of about 47.7 million tonnes. India’s Adani and France’s TotalEnergies started supplying natural gas in April to the grid from their 5 mtpa Dhamra LNG import facility located in Odisha, on India’s east coast. During April-August, Petronet LNG’s 17.5 mtpa Dahej terminal operated at 93.4 percent capacity, while Shell’s 5 mtpa Hazira terminal operated at 36 percent capacity, PPAC said. The Dhamra LNG terminal operated at 18.9 percent capacity, it said.
Sizzling oil worldwide, rising worries in India
The ghost of rising oil prices is back to haunt the economy. Brent crude oil prices are now hovering around $96 per barrel, up more than 30% since 31 May. The recent upward pressure on oil prices is primarily led by supply-side concerns, with Saudi Arabia and Russia deciding to extend their voluntary output cuts till the end of December. When oil prices rise, India tends to feel the heat as we import most of our oil requirements. Costlier oil pushes up the oil import bill, which ultimately weighs on the country’s current account deficit. But note that other Asian economies are also vulnerable to rising oil prices. “Within Asia, India, Thailand and the Philippines appear more vulnerable to higher oil prices,” said a Nomura Global Markets Research report dated 15 September.
Energy transition in uncharted waters: Panel
Oil India intends to remain focused on oil and natural gas, with the revenue from those sectors supporting the pursuit of other energy sources, Oil India chairman and managing director Ranjit Rath said on a panel today at the conference in Calgary, Alberta. “We would always look for more and more energy,” Rath said. “Biofuel will actually be a major, major game changer as far as the transition is concerned.” Brazil, which is a net exporter of oil but a net importer of fuel, has focused on the development of its biofuel industry, Brazilian oil and gas regulator ANP director general Rodolfo Saboia said. “If you ride a car on ethanol in Brazil, you would have a smaller footprint than riding an electric car which is moved by the energy matrix in Europe,” Saboia said. “This shows how important a role biofuels have to play during the energy transition.” Natural gas will be the fossil fuel of choice in the transition, according to Saboia, as Brazil strives to develop that market. Rath agreed with that assessment. “At the end of the day, you would like to have more natural gas as part of your primary energy basket,” Rath said, even as his company pursues partnerships to develop biofuels, green hydrogen and critical minerals. “So, there will be a strong focus on exploration and production.” Saboia’s organization regulates everything from the well to the retail fuel station and is keeping an eye on what policy-makers might do with the challenges they face. How the transition is managed could be quickly disrupted by technological advances, such as biofuels and synthetic fuels for internal combustion engines, Saboia said. “We are sailing in uncharted waters right now, so to articulate policies that might lead to a reasonable and effective way of addressing the energy transition is not a clear scenario,” said Saboia. “It’s always hazy.” With so many unanswered questions, the role of government and interactions between countries striving to find solutions will be critical, he said
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.