Oil Prices Soar As OPEC+ Shocks The Market
OPEC+ on Sunday surprised oil markets with an announcement that it will reduce its output further, by some 1.16 million barrels daily. Reuters noted in a report that with the new cut, the total output reduction amount from OPEC+ will come in at 3.66 million barrels daily, or 3.7% of global oil demand. The Financial Times reported that oil prices had gained 8% immediately after the announcement, noting Saudi Arabia’s share of the cuts would be almost half of the total, at 500,000 bpd. Russia, meanwhile, said it would extend the production cuts of 500,000 bpd it announced earlier this year until the end of 2023. The FT noted the unusual nature of the announcement as it was made outside the group’s regular monthly meetings, the next of which is taking place today. The U.S. administration expectedly criticized the move, saying it was not the time to cut production. “We don’t think cuts are advisable at this moment given market uncertainty — and we’ve made that clear,” a spokesperson for the National Security Council said, as quoted by The Hill. “But we’re focused on prices for American consumers, not barrels, and prices have come down significantly since last year, more than $1.50 per gallon from their peak last summer,” the spokesperson, who was not named in the Hill report, added. The move by OPEC+ to curb production further came after the sharp drop in oil prices last month, largely driven by concern about the banking industry after a couple of sizeable bank collapses in the United States. The events sparked concern about the stability of the Western banking system, reinforced by the near-death experience of Credit Suisse, and fear of a recession that would affect oil demand. “OPEC is taking pre-emptive steps in case of any possible demand reduction,” Energy Aspects’ Amrita Sen told Reuters.
Demand For Fuel Tankers Jumps Amid Global Trade Reshuffle
With global trade being upended by sanctions on Russia while Asia and the Middle East add refining capacity at the expense of the U.S. and Europe, orders for fuel tankers have soared so far this year to the highest in a decade. So far into 2023, a total of 38 mid-range fuel tankers have been ordered, the highest number since 2013, per data from shipbroker Braemar cited by Bloomberg. The new global trade order after the EU and G7 embargoes and price caps on Russian oil products, as well as the rise in Asian and Middle Eastern refining capacity while facilities closed in the U.S. and Europe, have created a wider geographical dislocation between new refining capacity and major consuming centers. Ahead of the EU ban on Russian petroleum products, Russia began to divert its oil product cargoes to North Africa and Asia. At the same time, Europe has started to buy more diesel and other fuels from the Middle East, Asia, and North America to replace the lost Russian barrels. Using ship-to-ship (STS) loadings, Russia is shortening the routes for tankers headed to Africa and Asia as Moscow is now banned from exporting fuels to the EU. At the same time, Europe is ramping up imports of diesel from the Middle East and Asia to offset the loss of Russian barrels, of which it imported around 600,000 barrels per day (bpd) before the February 5 embargo took effect. This dislocation of global trade in fuels, with the longer distances tankers are now having to travel to deliver Russian oil products outside Europe, is boosting demand for tankers hauling petroleum products. Moreover, the world’s refining capacity is expected to increase by nearly 3 million bpd by the end of 2023 when at least nine refinery projects are expected to start up in the Middle East and Asia, the EIA estimated last year. “The main, structural shift in the refinery landscape that will support refined-product shipping demand in the medium- and long-term is the geographical dislocation between new refineries and major consumers,” Alexandra Alatari, a senior analyst with Braemar, told Bloomberg.
How Oil Prices Have Reacted To Financial Crises Through History
Once infrequent, financial crises that require dramatic rescues are quickly becoming the norm. Each of the last four U.S. administrations has grappled with an economic crisis serious enough to warrant government intervention. The current banking crisis comes just three years after the Covid-19 pandemic triggered global supply chain disruptions, which itself came a little more than a decade after the 2008 financial crisis. Unfortunately, energy is one of the sectors that have historically been hammered the most whenever the economy ails. Economic downturns including recessions tend to have a pronounced negative impact on the oil and gas sector, leading to steep decline in oil and gas prices as well as contraction in credit. Falling oil and gas prices means lower revenues for oil and gas companies and tight credit conditions that result in many explorers and producers paying higher interest rates when raising capital, thus crimping earnings even more. Whereas quick action by the U.S. government appears to have stabilized the banking sector, some experts are warning that we are not out of the woods yet. Former PIMCO chief Mohamed El-Erian has criticized the Federal Reserve’s delayed action to control inflation, and says the central bank’s “least bad” option is to immediately pause its interest rate increases,”The degree of economic contagion that resulted from this mishandled interest rate cycle is going to be significant because there are two different drivers here. One is banks themselves getting more conservative and two is banks expecting regulation to get tighter. The regulators and the supervisors have been embarrassed and the response has always been tighter in regulation even though this is a failure of supervision more than a failure of regulation,” El-Erian has told CNBC. Let’s examine how energy markets have reacted to past economic and financial crises. The Great Depression of 1930 The opening of giant oil fields in the United States in the years heading into the Great Depression of 1930 led to an enormous glut and sent prices crashing to just 13 cents per barrel (~$5.40 today adjusted for inflation). In October 1929, U.S. commercial crude stocks hit a staggering 545 million barrels, thanks to the discovery of several massive oil fields in Oklahoma, Texas, the rest of the Southwest and California. Back then, that was the equivalent of 214 days of production; for some perspective, U.S. crude oil stocks were 845.27M for the week ending March 24, equivalent to ~42 days of production. The first gusher came online in 1926 in Oklahoma’s Seminole field, yielding 136 million barrels annually, or 10% of the entire U.S. oil output. A deluge of new discoveries in Oklahoma City, Yates field (West Texas), Van (East Texas), Signal Hill in California, and the super-giant Long Beach Oilfield within Greater Los Angeles quickly put an end to the peak oil fears prevalent in the early 1920s. By the summer of 1931, East Texas field alone was pumping 900,000 barrels per day from approximately 1200 wells, up from virtually zero just a few months prior. Unfortunately, too much oil flooded the markets and, compounded with low demand during the depression, triggered a dramatic oil price crash, with prices plunging from $1.88 per barrel in 1926 to $1.19 in 1930 and eventually 13 cents a barrel in the throes of the depression in July 1931. Oil Shock of 1973/74 The oil shock of 1973/74 is regarded as one of the most important oil crises after an oil embargo by Arab producers against the U.S. deepened the financial crisis of the early 1970s. In this case, it was high oil prices that actually triggered a severe economic crisis. On October 19, 1973, the Organization of Arab Petroleum Exporting Countries (OAPEC) slapped an oil embargo on the United States in response to President Nixon’s request to Congress to make available $2.2 billion in emergency aid to Israel for the Yom Kippur War. Consequently, OAPEC nations stopped all oil exports to the U.S., and started production cuts that lowered global oil supply. These cuts nearly led to a supply crunch and quadrupled the price of oil to $11.65 a barrel in January 1974 from $2.90 a barrel before the embargo. The embargo was eventually lifted in March 1974 amid disagreements within OAPEC members regarding how long it was to last. As the then Fed chair Arthur Burns observed, the embargo and manipulation of oil prices had come at most inopportune time for the United States. By the middle of 1973, prices of industrial commodities were already rising at more than 10% p.a. Industrial plants were operating at virtually full capacity leading to deep shortages of industrial materials. Meanwhile, the U.S. oil industry lacked excess production capacity, leading to wide oil deficits and fuel shortages everywhere. To make matters worse, OPEC was gaining significant market share while non-OPEC sources were in deep decline. This allowed OPEC to wield much more power and influence over the price setting mechanism in global oil markets. Following the devaluation of the dollar, OPEC nations resorted to pricing their oil in terms of gold and not USD, leading to a wild gold rally from $35 an ounce to $455 an ounce by the end of the 1970s. Ultimately, the oil crisis of 1973 and the accompanying inflation triggered a U-shaped recession characterized by a prolonged period of weak growth and economic contraction. The Oil Price Crisis of 1998–9 The oil price crisis of 1998/99 was the opposite extreme of what Americans who had lived through the oil price surges during the 1970s were accustomed to, with the Asian financial crisis triggering a dramatic decline in prices. The collapse of the Thai baht in the summer of 1997 marked the beginning of the oil price crash and led to the stock markets crashing 60%. Consequently, oil demand in Asia, a pillar of global demand, pulled back sharply with demand in other parts of the world also slumping. To exacerbate matters, OPEC production continued unhindered at a time when Iraqi oil had returned to global markets for
Sanjay Kumar going to be next Director (Marketing) of GAIL
Sanjay Kumar is set to be next Director (Marketing) of GAIL (India) Limited, a Mahartana PSU under the Ministry of Petroleum & Natural Gas (MoPNG). He has been recommended for the post by the Public Enterprises Selection Board (PESB) panel on Wednesday. Presently, he is serving as Executive Director in the same organisation. Kumar has been recommended for the post of Director (Marketing) of GAIL from a list of 10 candidates who were interviewed by the PESB panel in its selection meeting held on March 29. Out of 10 candidates, six candidates were from GAIL and one each from Bharat Sanchar Nigam Limited (BSNL), Indian Oil Corporation Limited (IOCL), Indian Railways Traffic Service (IRTS) and Hindalco Industries Limited. Director (Marketing) of GAIL, Kumar will be a member of the Board of Directors and will report to the Chairman and Managing Director (CMD). He will be heading the Marketing Division of the company. He will be primarily responsible for marketing operations of the company, including formulation and implementation of marketing policies keeping in view company’s profitability and objectives.
Concerns over long-term growth cast shadow on Petronet LNG
Although the near-term prospects of Petronet LNG (Petronet) look encouraging, growth, in the long run, appears a bit grim. The stock performance has also been underwhelming. The company’s scrip has generated a return of a mere 2 percent in the past month and 4 percent YTD. In the past three years, it is up 16 percent. Brokerage house Sharekhan said the stock offers a decent dividend yield of 5-6 percent, and it trades at an attractive valuation of 9.4 times its FY24 EPS or earnings per share and 8 times of FY25 EPS given earnings visibility and RoE (return on equity) of 22 percent. About the company Petronet imports, stores and sells regasified liquefied natural gas (LNG) in the domestic market. It accounts for around 40 percent of gas supplies in the country and its ports handle around two-thirds of LNG imports.
America’s LNG Problems Hit Banking Crisis Snags
The banking crisis that started with the failure of Silicon Valley Bank (SVB) is putting major U.S. LNG projects at risk, as rising interest rates and supply chain issues introduce financial challenges that have already led to delays. According to Reuters, two of four new projects that were slated for final investment decisions in Q1 of this year have seen the deadlines extended. Reuters cited Kpler’s lead natural gas analyst Eleni Papadopoulou as raising “concerns that banking lending activity might be pulled back” and we might see more FID delays due to the banking crisis. The delays are tied to export terminal projects by NextDecade and Energy Transfer LP, affected by rising interest rates, rising construction and labor costs and the disconnect between natural gas prices in the U.S. and the rest of the world. NextDecade has delayed construction of its Rio Grande LNG facility in Texas, and is now expecting an FDI by the end of Q2. In filings with the SEC, NextDecade said it had extended its construction agreements to June 15. The cost of the first three trains of Rio Grande LNG is estimated at $11.5 billion, with a 16 million tonnes per year capacity. According to Reuters, the French bank Societe Generale SA withdrew last year as the lead bank for Rio Grande. The two projects that are advancing without delay are Venture Global LNG’s project in Louisiana and Sempra Energy’s LNG project in Texas. Advancement now means that these promising big projects will have to rely much more significantly on advance offtake deals than on developer equity. In other words, the projects that will be able to move forward without any financial snags will likely be those that can contract their entire capacity in advance. That makes offtake deals even more important going forward. That also means dealing with volatile natural gas prices that make long-term offtake deals risky.
Saudi Aramco Bets On Continuous Growth Of Chinese Oil Demand
The world’s largest crude oil exporter, Saudi Arabia, is betting big on the growing market for crude China, as Saudi oil giant Aramco is strengthening its downstream presence and crude supply market share in the world’s top importer. Saudi Aramco announced this week two major refinery and petrochemical deals in China, which not only give the world’s largest oil firm a share of the Chinese downstream market but also an additional export outlet for 690,000 barrels per day (bpd) of Saudi crude in China. With the two agreements, Saudi Arabia is betting on continuous growth in Chinese oil demand on the one hand. On the other hand, the Kingdom is looking to boost its market share in the world’s top oil importer, where its partner in the OPEC+ pact, Russia, has gained market share with cheap crude after the Russian invasion of Ukraine and the sanctions on Moscow that followed. Saudi Arabia and Russia have been neck and neck on the Chinese oil market for years, but the fight for market share has become more contested since the war in Ukraine began as Russia pivoted to Asia and now bets on China and India as the key buyers of its crude, often offered at wide discounts to international benchmarks. Saudi Arabia sells its crude oil under long-term contracts, so it has a guaranteed share of the Chinese market. But Russia, having pivoted to Asia for crude and fuel sales after the Western sanctions, is offering its oil at discounts and could attract more Chinese buyers who don’t abide by the G7 price caps. Russia was the single largest crude oil supplier to China in January and February, overtaking Saudi Arabia, which was the number-one supplier of oil to China last year. As China accelerated the buying of cheap Russian crude oil at discounts to international benchmarks, Chinese imports of crude from Russia jumped by 23.8% year over year to 1.94 million bpd in January and February 2023, per data by China’s General Administration of Customs cited by Reuters. While Russia pushes to sell its crude—banned in the West—in Asia at discounts, Saudi Arabia is locking in long-term demand in China with stakes in refining and petrochemical projects. A Saudi Aramco joint venture plans to build a $10-billion refining and petrochemical complex in China over the next three years, the Saudi oil giant said on Sunday. The complex in northeast China will have the capacity to process 300,000 bpd, of which Aramco will supply 210,000 bpd. The project “represents a major milestone in our ongoing downstream expansion strategy in China and the wider region, which is an increasingly significant driver of global petrochemical demand,” Mohammed Al Qahtani, Aramco Executive Vice President of Downstream, said on Sunday. On the following day, Aramco said it would buy 10% in private refiner Rongsheng Petrochemical for the equivalent of $3.6 billion and would supply 480,000 bpd of Arabian crude oil to Rongsheng affiliate Zhejiang Petroleum and Chemical Co. Ltd (ZPC), under a long-term sales agreement. The two deals give Aramco a long-term export outlet to 690,000 bpd of Saudi crude to China, which would boost Saudi Arabia’s market share by locking in contracts for the coming years and decades. The acquisition “demonstrates Aramco’s long-term commitment to China and belief in the fundamentals of the Chinese petrochemicals sector,” Aramco’s Al Qahtani said. “It also promises to secure a reliable supply of essential crude to one of China’s most important refiners,” the executive added. Russia may be attracting Chinese buyers with cheaper spot cargoes, but Saudi Arabia is playing the long game with long-term contracts to lock in oil sales for decades.
ONGC to start oil production from KG block in May, gas in 2024
Oil and Natural Gas Corporation’s (ONGC) delayed Krishna Godavari basin KG-D5 project is likely to start crude oil production in May this year and gas output a year later, a senior company official said. ONGC was originally to start gas production from Cluster-II fields in block KG-DWN-98/2 (KG-D5) in June 2019 and the first oil was to flow in March 2020. The company blamed contracting and supply chains issues due to the pandemic for shifting the start of oil production first to November 2021, then to third quarter of 2022 and now to May 2023. Gas output start target was first revised to May 2021, then to May 2023 and now to May 2024. ONGC Director (production) Pankaj Kumar said a floating production unit, called FPSO, which will be used to produce oil, is already in Indian waters. “We estimate oil production should start in May,” he said. The block is currently producing 1.7 million standard cubic meters per day of natural gas. “We will start with 10,000 to 12,000 barrels per day and reach the peak of 45,000 bpd in 2-3 months,” he said adding some 2 mmscmd of gas would also flow with oil but actual gas output will start in May 2024 when 7-8 mmscmd production is expected. The production estimates are however much lower than what was originally projected. At the time of its launch in April 2018, ONGC had said the estimated capital expenditure would be USD 5.07 billion and operational expenditure would be USD 5.12 billion over a field life of 16 years. Kumar said the company hopes to arrest the decline in crude oil production in the next fiscal while natural gas output is likely to see a rise. ONGC’s KG-DWN-98/2 or KG-D5 block, which sits next to Reliance Industries’ KG-D6 block in the KG basin, has a number of discoveries that have been clubbed into clusters. It is situated offshore the Godavari river delta in the Bay of Bengal. It is located 35-km off the coast of Andhra Pradesh in water depths ranging from 300-3,200 metres. The discoveries in the block are divided into three clusters — Cluster-1, 2 and 3. Cluster 2 is being put to production first.
PNGRB Notifies Levelized Gas Pipeline Tariff
The Petroleum and Natural Gas Regulatory Board (PNGRB) has notified a levelized Unified Tariff of Rs.73.93/MMBTU. It and created three tariff zones for Unified Tariff, where the first zone is up to a distance of 300 kms from gas source, second zone is 300 – 1200 kms and third zone is beyond 1200 kms. The Zonal unified tariffs will be effective from 1st April 2023 and details of the same are webhosted on the PNGRB’s website(www.pngrb.gov.in). The national gas grid covers all the interconnected pipeline networks owned and operated by entities viz. Indian Oil Corporation Limited, Oil and Natural Gas Corporation Limited, GAIL (India) Limited, Pipeline Infrastructure Limited, Gujarat State Petronet Limited, Gujarat Gas Limited, Reliance Gas Pipelines Limited, GSPL India Gasnet Limited and GSPL India Transco Limited. With commissioning of newer interconnected pipelines, the national gas grid will keep expanding for Unified tariff. These entities will get the tariff as per their entitlement while customers would pay Unified tariff. The difference between the same will be settled between the Pipeline entities for which a settlement mechanism has been notified. The reform will specially benefit the consumers located in the far-flung areas where currently the additive tariff is applicable and facilitate development of gas markets and vision of government to increase the gas utilisation in the country.
Russia’s Rosneft signs deal to boost oil supplies to India
Russia’s largest oil producer Rosneft and India’s top refiner Indian Oil Corp have signed a term agreement to substantially increase oil supplies and diversify oil grades delivered to India, Rosneft said on Wednesday. The deal was signed during a working trip to India by Rosneft CEO Igor Sechin, the company said. Igor Sechin, Chief Executive Officer of Rosneft Oil Company, during his India visit met with officials from the Indian government, as well as with the heads of some of the country’s largest oil and gas companies. During the trip, Rosneft Oil Company and Indian Oil Company signed a term agreement to substantially increase oil supplies as well diversify the grades to India. Igor Sechin, CEO of Rosneft Oil Company, and Shrikant Madhav Vaidya, Chairman of Indian Oil Corporation Ltd., signed the agreement. They also discussed ways of expanding cooperation between Rosneft Oil Company and Indian companies in the entire value chain of the energy sector, including possibilities of making payments in national currencies. Rosneft CEO also discussed ongoing implementation of joint projects between Rosneft and its Indian partners, including Sakhalin-1, Taas-Yuryakh and Vankorneft. Driven largely by a surge in oil imports, Russia has emerged as one of the top 5 trading partners of India. Indian companies (ONGC Videsh Ltd., Oil India Limited, Indian Oil Corporation, and Bharat Petroresources) have been owners of 49.9% of the Rosneft’s subsidiary JSC Vankorneft since 2016. This company is located in Krasnoyarsk Territory and develops the Vankorskoye oil and gas condensate field, one of the biggest fields discovered and brought on stream over the last 25 years in Russia. A consortium of Indian companies (Oil India Limited, Indian Oil Corporation and Bharat Petroresources) also owns 29.9% of Taas-Yuryakh Neftegazodobycha, which develops the Central Block and the Kurungsky license block of the Srednebotuobinskoye field which is among Rosneft’s largest assets in Eastern Siberia.