Oil India Begins Exploration For Underground Oil & Natural Gas In Puri
Oil India, the nation’s second-biggest state-owned oil producer, on Sunday, began drilling to explore underground oil and natural gas at Gop Kushupur area in Puri district. According to reports, Oil India has taken eight-acre land in lease for three years and also paid compensation of Rs 10 million to families of 37 farmers displaced due to the project. Last year, extensive exploratory drilling and surveys had been carried out at an investment of Rs 12.48 billion, including Rs.2.20 billion in seismic surveys, at five coastal blocks and eight districts i.e. Puri, Khordha, Cuttack, Jagatsinghpur, Kendrapara, Jajpur, Bhadrak, and Balasore. After surveying 3000 square km of five blocks, oil and natural gas deposits were found at two places in Gop block. Eight acres of land at Kusupur Mouza and another eight acres of land at Chitra Mouza under Mahalpada panchayat were identified through satellite map.
ONGC wants govt to scrap windfall tax, $10 gas price
India’s top oil and gas producer ONGC wants the government to scrap windfall profit tax levied on domestically produced crude oil and instead use the dividend route to tap into bumper earnings resulting from surge in global energy prices. The firm also favours a floor price for natural gas at USD 10 per million British thermal unit — the current government-dictated rate — to help bring deposits in challenging areas to production, two sources aware of the matter said. State-owned Oil and Natural Gas Corporation (ONGC) management during discussions with government officials stated that levying windfall profit tax on domestic oil producers, while at the same time reaping rich savings from buying discounted oil from Russia was unfair. Buying discounted Russian crude oil, which was shunned by the West since the Ukraine conflict, has helped save Rs 350 billion and this savings should be ploughed back by boosting domestic output, they said. ONGC management has told the government the savings from Russian oil buy should be allowed to be passed on to the company which will invest the same in identified projects. It feels companies should be allowed to reap higher revenues and profits from elevated oil and gas prices instead of levying windfall profit tax on prices above a threshold. This higher profit can be then tapped for dividends which are a more equitable way of distributing wealth, the company management told the government. As per the extant guidelines, ONGC pays a minimum annual dividend of 30 per cent of net profit or 5 per cent of the net worth, whichever is higher. Following this policy, the firm will pay a higher dividend to the government, which holds almost 59 per cent shares in the firm, as well as other investors, boosting their confidence in the company. This would boost company share price and valuation, benefiting the government the most. This route will also allow the company to retain a fair amount of money for spending on finding oil and gas in unexplored areas and bringing even smaller resources to production which will ultimately help the nation cut down on its imports, sources said. India first imposed windfall profit tax on July 1, joining a growing number of nations that tax super normal profits of energy companies. Export duties of Rs 6 per litre (USD 12 per barrel) were levied on petrol and aviation turbine fuel and Rs 13 a litre (USD 26 a barrel) on diesel. A Rs 23,250 per tonne (USD 40 per barrel) windfall profit tax on domestic crude production was also levied. The duties were partially adjusted in the five rounds on July 20, August 2, August 19, September 1 and September 16, and were removed for petrol exports. Tax on domestically produced crude oil currently is Rs 10,500 per tonne while export duty on diesel is Rs 10 a litre and that on ATF is Rs 5. Sources said ONGC believes that allowing free market pricing of oil and gas will help attract big companies with technical knowhow and financial muscles. An ad-hoc tax adds to fiscal uncertainties for investors, they said. Following the similar principle, the government should also allow companies to discover market price for natural gas and tax only gains accruing over and above a minimum USD 10 per mmBtu threshold. While crude oil is priced at parity with international rates, the government currently fixes the price of natural gas bi-annually based on rates prevailing in gas-surplus nations like the US and Russia. Even this gas price fixation is now being reviewed with a view to bring down the rates for consumers. The cost of producing gas from deepsea and difficult areas such as high-pressure, high-temperature fields is very high and any attempt to artificially control rates would lead to investments in such fields becoming economically unviable, they said. ONGC has told the government that it recently discovered a price of USD 22 per mmBtu that users were willing to pay for its coal-bed methane (CBM) gas. The government could look to tax any price that accrues over and above USD 10, sources said. The government-dictated gas price for ONGC’s legacy fields is USD 6.1 per mmBtu for the six-month period ending September 30. The rate is close to USD 10 per mmBtu for difficult fields such as deepsea. These rates are expected to climb to over USD 9 per mmBtu and USD 12 respectively from October 1.
GAIL hunts for gas as Russia’s Gazprom turns off tap
GAIL India Ltd is looking for options to source liquefied natural gas (LNG) after Russian giant Gazprom halted supplies in May, three officials aware of the plans said. Efforts are underway to resume supplies, but no headway has been made, the official said, seeking anonymity. To bridge the deficit, state-run GAIL has also resorted to spot purchases in Qatar, the US and Australia, among others. The default in Gazprom’s contracted supplies has caused disquiet among stakeholders in the Indian energy sector. “Whenever there is a supply crunch, GAIL has to resort to minor supply cuts to its customers and also buy from the spot. They are just trying to manage. In cases where GAIL has back-to-back contracts, GAIL cannot cut supplies or else GAIL would have to pay the penalty here. So, wherever it cannot lower the supplies, there it is supplying after buying from the spot,” said one of the three officials, all of whom spoke on the condition of anonymity. Supplies from Gazprom have been stalled since May. In 2012, GAIL signed a contract with Gazprom Marketing and Trading Singapore, a subsidiary of Gazprom for the supply 2.5 million tonnes of liquefied natural gas annually for 20 years. Under the contract, two cargoes of LNG are to be supplied every month. Amid the crunch, India is also looking at diversifying its sources of gas and is looking for long-term contracts, the official cited above said. “National gas companies are working with different players…the US, Qatar, Mozambique. We are trying to get supplies from wherever possible at the best-suited prices. Nobody is willing to commit big long-term volumes before 2-3 years’ time,” the official added. Traditional sources of gas for India include Australia, Saudi Arabia, UAE, the US and Russia. GAIL has long-term contracts for around 14 million tonnes of LNG, and the Gazprom contract of 2.5 million tonnes accounts for 17.85% of its total contracted supplies. “The global energy markets are in such a situation that suppliers are willing to pay the penalty than honouring their long-term contracts. We are looking at all possible solutions to ensure we receive the contracted supplies,” a second official said. Noting that the Russian company’s unit Gazprom Germania falls under German jurisdiction, the official said that given the coming winter, Germany is looking to cater to its domestic demand. “The contract is still valid. While today there is high demand in the gas market, over the medium and long term, the demand will cool, and the largest taker will be India,” a third official said. GAIL is looking at all options to buy gas at an affordable price, the official said, adding the problem is not availability but the price. Queries sent to GAIL, Gazprom, the ministry of petroleum and natural gas, the ministry of external affairs and the Russian embassy in Delhi remained unanswered till press time.
Oil Prices Are On Track For A Third Consecutive Week Of Losses
Crude oil is about to book its third consecutive week of losses despite several spikes as worry about demand remains stronger than worry about supply. A strong dollar also pressured oil prices as it made the commodity less affordable for buyers in the dollar-dominated oil market. At the time of writing, Brent crude was trading at $91.24 per barrel, with West Texas Intermediate at $85.39 per barrel. Recession fears, however, remain the biggest reason behind the downward trend. The World Bank on Thursday warned that the risk of a global recession had risen recently, noting the rush by central banks to raise interest rates. According to the WB, if the rate hikes were done too fast, this would push the global economy into a slowdown. “Central banks around the world have been raising interest rates this year with a degree of synchronicity not seen over the past five decades — a trend that is likely to continue well into next year,” the World Bank said. “Global growth is slowing sharply, with further slowing likely as more countries fall into recession. My deep concern is that these trends will persist, with long-lasting consequences that are devastating for people in emerging market and developing economies,” the WB’s president, David Malpass commented. A recession would damage oil demand just as it would damage pretty much everything else as well, which would help tame inflation but at a very high cost. Alternatives, however, are scarce. The European Union has reiterated its dedication to sanctions on Russia, with an embargo on Russian crude set to come into effect in three months and an embargo on fuels coming into effect in five. This is bound to affect prices for both crude and fuels, especially diesel as global diesel stocks are tighter than usual at the moment. Until the embargos come into effect, however, the downward pressure on prices will remain substantial, keeping a lid on benchmarks.
IEA: Russian Crude Ban Will Take 2.4 Million Bpd Off The Market
As the European Union prepares to implement a ban on Russian seaborne crude in December, the market will have to prepare itself for a loss of 2.4 million bpd, according to the International Energy Agency (IEA). The ban on Russian crude imports by sea will take 1.4 million bpd of oil off the market, along with 1 million bpd of petroleum products. This is in line with the ban on Russian seaborne crude that goes into effect on December 5th, and the embargo on petroleum products, which goes into effect on February 5, 2023. In addition, due to the pending EU ban on maritime services, the IEA expects forced reallocations from countries that are not on board with the G7’s own proposed price cap on Russian oil. The G7 is reportedly considering sanctions on oil importers who refuse to comply with the group’s proposed price cap on Russian oil, which has prompted threats from Mosocw to withhold oil from the market. Furthermore, by February next year, the IEA predicts that total Russian oil production will decline to 9.5 million bpd, which represents a 1.9 million bpd plunge year-on-year. This comes after the IEA said in August that Western sanctions were not significantly impacting Russian oil output, as rerouting of crude to Asia had served as a stop-gap measure. The new Russian barrels will also have to find new buyers in Asia to mitigate any negative effects on Russian revenues. The oil market remains highly volatile as it attempts to determine whether fears of declining demand–particularly coming out of China’s COVID lockdowns–or tight supply will rule fundamentals. The IEA highlighted decelerating growth in global oil demand in its latest monthly report, but also noted that due to significant gas-to-oil switching, total demand growth was actually only slightly lower. In the meantime, heading into the ban, Europe continues to import large volumes of Russian crude, with Bloomberg recording 1 million bpd of imports in the week ending September 2. While that figure is higher than August, it is also lower than June.
Bid to Ease Crisis: Energy Update
France is planning to cap energy-price hikes for households at 15% starting next year as it seeks to ease the financial pain of an energy crisis that has gripped the continent. The European Commission earlier proposed a mandatory cut on energy use in the bloc, as well as steps to ease the crunch in markets caused by ballooning collateral demands. Commission President Ursula von der Leyen laid out plans to raise 140 billion euros from energy companies’ profits. The changes all need to be signed off by member states and discussions won’t be easy. Gas prices rose, following extreme volatility in recent weeks. They’re about eight times higher than the typical levels for this time of the year, underscoring the challenge policy makers face. France to Cap Price Hikes From January France said it will limit energy price increases to 15% for households from the start of next year to ease the burden of the energy crisis on consumers. The caps will cost the government a net 16 billion euros ($16 billion) in 2023, Finance Minister Bruno Le Maire said. Prices would have risen by 120% without the limit, he said. The state will also continue handing over subsidies, with a one-time payment of up to 200 euros each going to 12 million poorer households, Prime Minister Elisabeth Borne said. French Grids Urge Less Fuel Use France’s gas system can cope with demand for an “average” winter, as well as underpinning the power sector and contributing to Europe’s “solidarity,” grid operators GRTgaz and Terega said in a statement. In a very cold winter, the gas deficit for the period could reach 5% of French winter demand. Cold snaps are easier to manage in the first part of winter due to larger storage-injection capacities. Meanwhile, France is working on capacity to send 100 GWh/day of natural gas to Germany from October, GRTgaz chief Thierry Trouve said at a press conference. The would go through a pipeline previously used to send flows from Germany to France. EU Proposes Easier Collateral Rules The Commission has proposed a series of regulatory changes that could help mitigate the liquidity crisis currently ripping through the continent’s energy providers. Measures include raising the clearing threshold for commodities and other derivatives to €4 billion ($4 billion) and allowing bank guarantees to be accepted as collateral against margin calls, according to the document.
Gas policy shifts divert focus from LNG sea changes
2022 has seen the specter of government interventions envelop gas markets: whether it’s price caps, encouraging benchmark diversification, pooling procurement in a centralized platform or using state-owned banks to directly buy LNG cargoes, all ideas appeared to be on the table. While pipeline gas and LNG share several fundamental attributes, they are also different in many aspects. In this flurry of policy proposals and announcements, there are significant changes taking place in the LNG industry itself. These changes relate to price indexation, market participation and trade flows. This piece, as part of a series of articles on LNG industrychanges, will tackle the first point: price indexation. LNG price markers are being used in the spot market, while long-term contracts are still prone to utilizing substitute oil or pipeline gas prices. As substitute prices diverge significantly from the LNG market, a hybrid solution in long-term contracts, combining both mechanisms, is seeing some adoption. Price indexation Price benchmarks used in LNG trade have been in great flux over the last 12 months, triggering large changes in relative values between them. While LNG has always been a difficult market to analyze from a pricing perspective, 2022 has seen this complexity deepen. Here are some broad points to start with, based on data collected by market reporting teams at Platts, part of S&P Global Commodity Insights, and the IHS Connect contract database from January to August: • Fixed price trade has globally been in retreat for some time, but North Asia’s usage of fixed prices significantly slumped in 2022; • As LNG cargo prices have converged and gas hub prices have diverged an increasing amount of trade referenced LNG-based benchmarks; and • Contracts signed for long-term volumes are on course to surpass 2021’s total with ease while crude oil-linked contracts have dropped significantly as a proportion of total trade. Fixed price trade has dropped to around 43% of total spot and short-term trades, or cargoes for delivery within the next two years or so, in 2022 versus 65% of trade in 2021. Digging deeper, fixed price trade in North Asia has fallen from 52% in 2021 to under 20% so far in 2022. Fixed prices now largely appear in tenders issued by state-owned companies in South Asia, Thailand, and Argentina. These locations account for 75% of fixed price trades in 2022. The significant drop in fixed price trades is due to increased market volatility and more developed futures markets. It has been well documented that LNG prices (JKM, Platts West India Marker, Platts Northwest Europe, Platts Gulf Coast Marker) have been moving in a tight band while gas hub prices on either side of the Atlantic (represented by Henry Hub and the Dutch Title Transfer Facility, or TTF) have been at record differentials. Added to this, LNG prices have been trading at large discounts to TTF in 2022. Platts Northwest Europe LNG benchmark reached a record discount of $24.475/MMBtu against Dutch TTF on Aug. 26. It is in this context that the amount of JKM-indexed trade in the spot and short-term market globally increased to some 33% in 2022, more than double the 2021 figure. Also apparent from this data is that within Europe itself there is greater variety of indexation being used for LNG cargoes. For example, a recent tender issued requested pricing against the French PEG gas hub for 12 cargoes delivered between 2023 and 2025. Activity reported in the Atlantic LNG Market on Close assessment process of S&P Global indicates this, with almost 40% being reported against the UK’s NBP in 2022. There was no NBP-indexed activity reported in the process in 2021. A peculiarity specific to LNG is the appearance of substitute prices in the long-term contract space. It is also surprising that these substitute prices very rarely appear in the short-term contract space. Henry Hub and Brent, widely used in long-term contracts ex-US and within Asia respectively, are each used less than 5% in near-term trade. While Henry Hub has appeared considerably more in long-term Sales and Purchase Agreements (SPAs) in 2022 – largely due to most of the projects seeking a final investment decision being based in North America – Brent-linked long-term contracts have foundered. According to IHS Connect’s LNG contract database just 0.675 million mt of purely Brent-linked SPAs have been signed so far this year, compared to nearly 18 million mt of such SPAs in 2021. Companies involved in negotiations for contracts that may conclude on a Brent-linked basis have complained that the relationship between LNG prices and Brent slope levels used in historical contracts has become a moving target. Because LNG prices are elevated relative to historical Brent slopes, buyers see a risk in agreeing to contracts now that would leave them at historically high slope levels with a risk of downwards LNG price movement. Sellers also do not want to leave value on the table given the potential to sell LNG in the next few years at considerably higher prices – based on current forward curve values – than historical Brent slope levels would imply. After having a reasonably steady relationship for many years the LNG price-Brent term slope relationship started to crack from 2019 onwards. However, the differences between the two have been greatest since 2021. The few purely Brent-linked term contracts signed this year were agreed in January. Platts has heard of several companies having protracted negotiations for term contracts with a proposed Brent pricing basis, but there is little breakthrough yet on these. For the few short-term tenders concluded on Brent-linked pricing, from winter season strips of cargoes to agreements for deliveries up to two years ahead, the slopes have reportedly been between 20%-35%. This reflects the difficulty of using substitute price benchmarks, as they do not share the same market fundamentals as the LNG market. The current impasse is probably unhelpful for the industry given that consumers are keen to tie down volumes for the next few years when the market is expected to be tight, and producers are
India’s oil imports from Russia jumped to 18% of crude purchases in July
India’s import of Russian oil rose to nearly 18 percent of its total petroleum crude imports in July in value terms, according to the latest commerce ministry data. As per the data, India imported Russian petroleum crude worth $2.88 billion in July, down a marginal 0.4 percent from the June figure of $2.89 billion. However, with India’s petroleum crude imports falling by more than a billion dollars in July from June, Russian oil amounted to 17.9 percent – compared to 16.8 percent in June – as a percentage of total petroleum crude imports. Country-wise import data for August is not yet available. Provisional data for trade in August, released on September 14, showed imports of petroleum, crude and products increased to $17.7 billion last month from $16.11 billion in July. The rise in Russian oil imports in recent months has been remarkable, with the Indian government taking advantage of the discounts that have been offered. Last week, Finance Minister Nirmala Sitharaman praised Prime Minister Narendra Modi for taking the decision to quickly ramp up Russia’s oil imports even in the face of sanctions announced following its invasion of Ukraine in late February. “Wherever there are sanctions, countries are finding their own ways to get Russian crude, Russian gas. That also is a part of inflation management,” the finance minister had added. In April-July, India’s import of petroleum crude from Russia totalled $8.95 billion. In contrast, the figure for the entirety of FY22 was $9.87 billion. The pace with which Russia has become a key source of petroleum crude for India can also be gauged by the following: in April, Russian oil made up 8.4 percent of India’s total petroleum crude imports. This figure rose to 12.8 percent in May, 16.8 percent in June, and finally 17.9 percent in July. The rapid rise of Russian oil imports meant it became India’s second-largest source of petroleum crude in June after overtaking Saudi Arabia. It is now on track to cross the leader, Iraq, in the coming months. In July, India imported $3.2 billion worth of petroleum crude from Iraq, just $321.7 million more than what was imported from Russia. In volume terms, oil imported from Iraq exceeded that from Russia by a mere 0.28 million tonne.
Analysts May Have Overhyped America’s Largest Oil Basin
Current forecasts of U.S. crude oil production growth may have to be significantly revised as the recent slide in active drilling rigs in the top shale basin, the Permian, suggests that output may disappoint due to supply chain constraints and cost inflation in the double digits. The rig count in the Permian Basin dropped by 2 to 340 last week, as the number of total active drilling rigs in the United States dropped by 1, according to new data from Baker Hughes published on Friday. The active oil rigs in the Permian now number 316 – the lowest in four months. This suggests that the most prolific U.S. shale basin, which continues to drive America’s oil production growth, is going through “a significant slowdown,” Bloomberg Opinion columnist Javier Blas argues. The slowdown in activity, as evidenced by the drop in active oil rigs from 331 in July to 316 now, points to the fact that forecasts of Permian output, and by extension, U.S. crude oil production growth, need to be recalibrated lower. As shale drillers prioritize returns to shareholders and paying down debts, they are not rushing to drill even at $90 or $100 oil. Even those planning an increase in drilling activity face supply chain delays and up to 20% higher costs. At the same time, the Energy Information Administration said in its latest Drilling Productivity Report this week that crude oil production in the Permian is set to hit a record high next month, adding 66,000 bpd from September to reach 5.413 million bpd in October. Yet not everyone is so optimistic: Pioneer Natural Resources CEO Scott Sheffield said last week that U.S. oil production growth would likely disappoint both this year and next. Sheffield has forecast that U.S. oil production will add 500,000 bpd this year but in 2023 the production gains may be lower than this, due to constraints, Reuters reported last week. The EIA forecasts production growth of 800,000 bpd for 2023.
China And Russia Move To Disrupt The Dollar’s Dominance In Oil Markets
The long-mooted prospect of the end of the U.S. dollar’s hegemony in the global oil and gas markets took another step towards realisation last week with the announcement that Russian and Chinese hydrocarbons giants, Gazprom and China National Petroleum Corporation (CNPC) have agreed to switch payments for gas supplies to rubles (RUB) and renminbi (RMB) instead of dollars. In the first phase of the new payments system, this will apply to Russian gas supplies to China via the ‘Power of Siberia’ eastern pipeline route that totals at minimum 38 billion cubic metres of gas per year (bcm/y). After that, further expansion of the new payments scheme will be rolled out. It is apposite to note at this point that although ongoing international sanctions against Russia over its invasion of Ukraine in February has provided the final impetus for this crucial change in payment methodology, it has been a core strategy of China’s from at least 2010 to challenge the U.S. dollar’s position as the world’s de facto reserve currency. China has long regarded the position of its renminbi currency in the global league table of currencies as being a reflection of its own geopolitical and economic importance on the world stage. As analysed in depth in my latest book on the global oil markets, an early indication of China’s ambition for the RMB was evident at the G20 summit in London in April 2010, when Zhou Xiaochuan, then-governor of the People’s Bank of China (PBOC), flagged the notion that the Chinese wanted a new global reserve currency to replace the U.S. dollar at some point. He added that the RMB’s inclusion in the IMF’s Special Drawing Right (SDR) reserve asset mix would be a key stepping-stone in this context. At that time, at least 75 percent of the then-US$4 trillion daily turnover in the global foreign exchange (FX) markets, as determined by the Bank for International Settlements (BIS), was accounted for by the ‘Big Four’ international currencies: the U.S. dollar (USD), the Eurozone’s euro (EUR), the British pound (GBP), and the Japanese yen (JPY). Aside from dominating daily FX markets turnover, currencies in the SDR also dominate in the payment, reserves, and investment currency functions in the global economy. Enormous media fanfare in China followed the RMB’s inclusion in the SDR mix in October 2016, when it was assigned a weighting of 10.9 percent (the USD had a 41.9 percent share, the EUR 37.4 percent, GBP 11.3 percent, and JPY 9.4 percent). As of 2022, the RMB’s share in the SDR mix has risen to 12.28 percent, which China still regards as not truly befitting its rising superpower status in the world. China has also long been acutely aware of the fact that, as the largest annual gross crude oil importer in the world since 2017 (and the world’s largest net importer of total petroleum and other liquid fuels in 2013), it is subject to the vagaries of U.S. foreign policy tangentially through the oil pricing mechanism of the U.S. dollar. This view of the U.S. dollar as a weapon has been powerfully reinforced since Russia’s invasion of Ukraine and the accompanying U.S.-led sanctions that have followed, the most severe of which – as with sanctions on Iran from 2018 – relate to exclusion from use of the U.S. dollar. The former executive vice-president of the Bank of China, Zhang Yanling, said in a speech in April that the latest sanctions against Russia would “cause the U.S. to lose its credibility and undermine the [U.S.] dollar’s hegemony in the long run.” She further suggested that China should help the world “get rid of the dollar hegemony sooner rather than later.” Russia itself has long held the same view on the advantages for it of removing the U.S. dollar’s hegemony in global hydrocarbons pricing, but, while China was unwilling to overtly challenge the U.S. during the height of its Trade War under the highly unpredictable former U.S. President Donald Trump, it could do little about it on its own. A sign of Russia’s intent, though, came just after the U.S. reimposed sanctions in 2018 on its key Middle Eastern partner, Iran, when the chief executive officer of Russia’s Novatek, Leonid Mikhelson, said in September of that year that Russia had been discussing switching way from US$-centric trading with its largest trading partners such as India and China, and that even Arab countries were thinking about it. “If they [the U.S.] do create difficulties for our Russian banks then all we have to do is replace dollars,” he added. At around the same time, China launched its now extremely successful Shanghai Futures Exchange with oil contracts denominated in yuan (the trading unit of the renminbi currency). Such a strategy was also tested initially at scale in 2014 when Gazpromneft tried trading cargoes of crude oil in Chinese yuan and rubles with China and Europe. This idea again resurfaced following the latest international sanctions imposed on Russia following its invasion of Ukraine. Almost as soon as they were introduced, Russian President Vladimir Putin signed a decree requiring buyers of Russian gas in the European Union (EU) to pay in rubles via a new currency conversion mechanism or risk having supplies suspended. This threat nearly succeeded in exploiting existing fault lines running through the U.S.-led NATO alliance, as major EU consumers of Russian gas scrambled to work out how to appease Putin’s ruble payment demands, without overtly breaking any sanctions. Since then, Russia has simply toyed with the EU over ongoing gas supplies, most recently last week with its statement that it has scrapped the resumption of on/off supplies from the Nord Stream 1 pipeline – one of the main supply routes to Europe – after “discovering a fault during maintenance.” The scale and scope of this implicit threat was underlined again last week when Putin said that Russia might cut off all energy supplies to the EU if price caps are imposed on Russia’s oil and gas exports. The further expansion of