The European Union’s Stability and Growth Pact, which sets fiscal rules for its member states, is like the emperor’s new clothes. Almost everyone sees it has none, yet few admit it openly. This disingenuous silence is bad economics and bad politics.
For starters, the pact’s rules are so hopelessly complex that almost no government minister, let alone member of parliament, can decipher them. There are now various reform proposals that aim to simplify things, including by a group of French and German economists to which I belong.
Most of these proposals would place less emphasis on estimating member states’ cyclically-adjusted budget deficits – a notoriously difficult calculation – and focus instead on monitoring growth in public spending. Concretely, each government would commit to expenditures consistent with the country’s economic growth outlook and expected tax receipts, and in line with a medium-term debt target. There would be less micromanagement by EU institutions, more room for national decision-making, and more responsibility for individual governments.
Ministers have so far shown no appetite for such radical reform. But there is now a second reason to overhaul the EU’s fiscal framework: today’s economic conditions are very different from those when the pact was designed over two decades ago. “When facts change, I change my mind,” John Maynard Keynes famously said. And the facts have certainly changed.
The pact entered into force in 1997. At the time, the median public debt among the 11 EU countries that would initially adopt the euro was 60% of GDP, while the forecast was 3% growth and 2% inflation. The risk-free long-term interest rate – at which most eurozone countries would soon borrow – was 5%. Stabilising the debt ratio at its prevailing 60% level therefore required governments to keep their budget deficits below 3% of GDP – or, put another way, to maintain a primary budget balance (revenues minus spending, excluding interest payments) of zero.
Such guidelines made sense. If growth faltered, revenue shrank, or markets started pricing in a default, there would be a real risk of debt spiralling out of control – as Europe’s sovereign-debt crisis of 2010-2012 later showed. The 3%-of-GDP deficit threshold that triggers the activation of a stronger policy monitoring procedure was thus a rough but reasonably calibrated benchmark. Moreover, it was wise to aim for significantly lower deficits, in order to maintain a safety margin.
In 2019, the median debt for the same 11 countries is 70% of GDP, while the International Monetary Fund currently forecasts 1.5% growth and 2% inflation (debt is a bit lower and growth a bit higher if all eurozone members are included). True, projected growth is half the level it was in 1997. Nonetheless, stabilising the debt ratio requires keeping budget deficits below 2.5% of GDP, which remains close to the pact’s 3% limit.
The big change from two decades ago, however, is the collapse in interest rates. Investors were recently willing to buy ten-year German government bonds yielding essentially nothing. Taking inflation into account, the real cost of German debt is significantly negative – as it is, to a lesser degree, for France, Spain, and most other eurozone members. Even Italy, with debt exceeding 130% of GDP and dismal growth, was able to borrow at 2.6%, or 2.4 percentage points less than Germany in 1997.
Under such conditions, a budget-deficit limit of 3% of GDP is, in fact, fairly lax. If long-term interest rates remain near zero for a few more years, governments will be able to run primary deficits greater than 2% of GDP without exceeding that limit. Many EU countries are likely to use this opportunity to finance current spending on the cheap. But should financial conditions change abruptly, they will be forced to adjust precipitously.
The European Commission insists that the 3% threshold is only an upper limit. Reforms to the pact in 2011 have tightened the screws. Eurozone countries are expected to keep their structural budget deficit (corrected for cyclical effects) close to zero, and those with a debt ratio exceeding 60% of GDP are mandated to reduce it.
However, the resulting constraints are too tight. The zero target for the structural deficit prevents governments from borrowing at today’s negative real interest rates to finance investments and reforms. And, as Olivier Blanchard of the Peterson Institute has forcefully argued, there is no compelling economic reason to cut debt when borrowing is costless.
The EU sits between a rock and a hard place. It should not let member states make a habit of financing recurring current expenditures with debt. But nor should it prevent them from taking advantage of persistently low interest rates to finance economically sound investments that will benefit future generations.
Europe should therefore reform its fiscal framework. Deficit hawks (especially in Germany) will no doubt protest, but prohibition without a rationale is politically unsustainable. Why wouldn’t EU citizens accept channelling debt-financed public investments into environmental research, renewable energy, clean transportation systems, and other efforts to contain climate change, when financial conditions would make such investments collectively profitable? Longstanding criticism of the pact for neglecting the distinction between investment and current spending is valid, to the extent that investment is defined economically rather than in accounting terms.
The EU should therefore agree on a set of goals – such as the transition to a low-carbon economy, broader access to employment, and output-enhancing economic reforms – that justify public spending temporarily in excess of the fiscal rule (unless, of course, the country is in a financially precarious state). Such an exemption should be conditional on long-term interest rates remaining exceptionally low. If rates were to rise, governments would have to trim and eventually discontinue these investments.
The need to revise the EU’s fiscal rules is clear. The main political parties competing in May’s European Parliament elections should recognise it and make the case openly. At a time when the EU’s very purpose is being questioned, economics taboos are the last thing Europe needs. – Project Syndicate
l Jean Pisani-Ferry, a professor at the Hertie School of Governance (Berlin) and Sciences Po (Paris), holds the Tommaso Padoa-Schioppa chair at the European University Institute and is a senior fellow at Bruegel, a Brussels-based think tank.

Britain’s appetite for natural gas usually declines in the summer, but this season is different with a record number of LNG tankers due to land this month.

The incoming cargoes show no sign of slowing, and will keep the pressure on benchmark prices already trading below their five-year seasonal average. That’s good news for factories and households as Brexit clouds the nation’s economic outlook.

“We can expect a significant pressure on prices this summer,” said Murray Douglas, a research director for European gas at Wood Mackenzie Ltd. “The global LNG market is strong, we will still have a lots of LNG turning from the Asian to the European markets and we still see lots of LNG deals” and approvals for new projects.

Cargoes are heading to the U.K. and other northwest European nations because thanks to the extensive infrastructure and traded hubs they can absorb any global surplus as well as handle a growing worldwide production boom. Britain is still taking imports of the super-chilled commodity even after its gas export pipeline shut for repairs this month.

LNG prices in Asia, the biggest consumer of the fuel, have also been too low to spur traders to ship cargoes east. Cooler weather is also supporting demand in the U.K.

While Asian LNG spot prices have regained their traditional premium over European hubs, Atlantic basin suppliers such as the U.S. and west Africa are still sending most of their cargoes to Europe, their nearest liquid market. Longer term, more plants are due to start producing LNG and a number of projects from Mozambique to Russia are nearing investment decisions this year.

U.S. President Donald Trump may use Europe’s increased appetite for LNG to promote his country’s fuel in the region when he visits the U.K. in June, according to Leslie Palti-Guzman, president and founder of consultant GasVista LLC in New York. In addition, the European Union and the U.S. will hold a forum in Brussels on May 2 to discuss bringing natural gas originated from shale fields in the U.S. to nations from Germany to Greece.

U.K. shipments are mainly sourced from the biggest exporter Qatar, as well as countries such as Nigeria and Norway, but the U.S. is becoming a bigger supplier. Britain is now among the top-10 importers of American LNG this year.

“This surge in U.K.-U.S. trade flow will bode well with the June visit of President Trump to the U.K., who has repeatedly used U.S. LNG as a tool in trade negotiations,” Palti-Guzman said by email. “The U.K. will be able to trumpet the increase in U.S. LNG imports to reinforce its trade relationship with the U.S., especially post-Brexit.”

Since March, Norway has reduced its overall gas shipments by about 16 percent for pipeline maintenance, cutting flows into the U.K.’s key Easington terminal by more than 80 percent. Meanwhile, the main U.K. export route, the Interconnector pipeline between England and Belgium, closed for repairs last weekend until May 1, cutting off a key transit route for flows into mainland Europe.

“April looks like being a record high import month for LNG into the U.K., and the Interconnector being offline means the U.K. market has no way of shipping gas back to the continent via pipeline,” said Alun Davies, director of Europe power and gas at IHS Markit.

— With assistance by Kevin Varley

Energy giant BP boosted its pre-tax earnings in the first three months of 2019, which it said showed “resilience” in a “volatile period”.

Pre-tax profits were £3.6bn, more than double that of the previous quarter at £1.7bn and higher the same period last year at £3bn.

However, the firm said its underlying replacement cost profits were £1.7bn, down from £1.9bn from the same period last year reflecting weaker oil prices and margin environment at the start of the quarter.

Capital expenditure was significantly lower compared to Q4 last year, which included £1.3bn as part of an asset swap agreement for ConocoPhillips’ 16.5% stake in the Clair field in the West of Shetland in December.

Upstream production was two percent higher than the previous year at 2.6billion barrels of oil equivalent per day, thanks to the acquisition of BHP Billiton’s assets.

Revenues were £52.1bn, down slightly from £53.4bn in Q1 2018.

BP said it was hit by the weaker oil price at the start of the quarter which has since recovered to around $70 a barrel.

The firm also made £463m in payments for the 2010 oil spill in the Gulf of Mexico this quarter.

One of the key events for the firm in the period was the final investment decision being taken on the Seagull development in the Central North Sea, as well at Atlantis Phase 3 in the Gulf of Mexico and Azeri Central East in Azerbaijan.

Chief executive Bob Dudley said: “BP’s performance this quarter demonstrates the strength of our strategy.

“With solid Upstream and Downstream delivery and strong trading results, we produced resilient earnings and cash flow through a volatile period that began with weak market conditions and included significant turnarounds.

“Moving through the year, we will keep our focus on disciplined growth, with efficient project execution and safe and reliable operations.”

New natural gas discoveries offshore Cyprus have revived the possibility of the island hosting an LNG plant

Cyprus is finally in a position where it can realistically start exploring a number of ways of getting natural gas to market. Seven years after the first discovery in Cyprus’ offshore economic exclusion zone (EEZ) — the Aphrodite field in Block 12 (4.5tn ft³ of gas in place) — the island has notched up two more finds.

Last year, an Eni-Total consortium struck gas at Calypso in Block 6 (estimated 3-5tn ft³). The most recent newcomer is Glaucus-1 (5-8tn ft³) in Block 10, discovered by ExxonMobil, partnered by Qatar Petroleum.

Energy minister Yiorgos Lakkotrypis, addressing Gulf Energy’s Eastern Mediterranean Gas Conference in Nicosia in early March, said the “quality of the reservoir in Block 10 allows us to be optimistic about the very high recoverability potential” of the ExxonMobil discovery. Last year, the first well drilled on Block 10 failed to find commercial reserves. With the Glaucos success, “we are waiting for the remodelling or re-calibrating of geological data and will look again at Block 10 targets”.

Sounding upbeat, Lakkotrypis was keen to move on to the subject of how to monetise “the discoveries we’ve had — and hopefully we’ll be having some more”. At present, the plan is for gas from Aphrodite to be exported to Egypt by pipeline. As for the other resources, “a number of parameters will determine what choice we will make, and until that moment comes we will be maturing all options together”.

LNG option favoured

According to Andreas Koutsoulides, commercial manager of the state energy firm Cyprus Hydrocarbons Company (CHC), four monetisation options are under review. The first would involve the construction of an LNG plant at Vasilikos on the southern coast of Cyprus. In the aftermath of the Aphrodite discovery a plant site was prepared and a master plan drawn up. But the scheme was deemed commercially unviable, given the limited discoveries off Cyprus at the time. Koutsoulides adds the venture would require “a minimum threshold of 10-15tn ft³ of resources to enable such a plant to go ahead”. The LNG proposal “is number one in terms of strategy because not only is it a solution that can bring upstream revenue to the country, but it will also have additional effects on the domestic economy in terms of employment and significant industrial activity”.

The second option is to export gas to the Egyptian market. The CHC executive sees potential demand in the domestic Egyptian market and for liquefaction, with capacity in the two existing LNG plants, Idku and Damietta. Plans for monetising Aphrodite gas “are crystallising towards Egypt because of the supply and demand structure there, the availability of infrastructure and changes in the gas market regulatory framework”.

The third option is for a floating LNG plant, which offers “tried-and-tested technology and we are looking at that very seriously. A floating facility gives lots of flexibility to move onto another field. Also, the threshold for the resources required to get a project up and running is lower than for an onshore facility.”

Pipeline to Europe

The final option is the East Med Gas Pipeline project that envisages natural gas from Israel and Cyprus being transported for sale in the markets of northern Europe. “There has been a sharp decline in Europe’s energy supply,” Koutsoulides says, “and they have been looking for years for diversification of supply.” FEED studies for the project have started.

In the view of East Med energy consultant Charles Ellinas, the Cypriot authorities should concentrate on the first of the four options: an onshore LNG plant—” a three-train facility to keep the unit costs down.” The gas resources could come from fields offshore Cyprus, and from the Leviathan field off Israel (22tn ft³ of gas in place). The Leviathan project, Ellinas says, “is having some troubles finding customers”. Future finds from fields offshore Israel operated by Energean might also find their way to Cyprus for liquefaction. A company spokesman tells Petroleum Economist that Energean is “examining all potential export routes for its gas fields in Israel”.

Attracting Israeli gas to Cyprus could be geopolitically advantageous for the island. Turkey, which opposes the exploitation of Cypriot gas while the island remains divided and which claims sovereignty of some of Cyprus’ EEZ, says it plans to drill off southern Cyprus—a potentially destabilising prospect for the Cypriot energy sector. But such a move could also threaten Israel’s interests, if its gas reached the island; and Turkey might think twice before risking confrontation with Israel.

Imports enthusiasm wanes

Another factor that both Cyprus and Israel have to take into account is Egypt’s rising gas production and its diminishing hunger for imports. Egyptian company, Dolphinus Holdings, has signed a 10-year contract with Noble Energy and Delek Drilling for gas supply from Israel’s offshore fields to Egypt. But a number of technical and security issues have yet to be resolved. Also, new discoveries, such as the one expected at Eni’s offshore Nour field, will boost still further Egypt’s reserves, adding to the 30tn ft³ at the mega-giant Zohr field. Enthusiasm for importing gas from elsewhere is likely to fall sharply.

In the chaotic aftermath of the 2011 popular uprising, Egypt was forced to import LNG. Now it is resuming its own LNG exports. “If the minister of petroleum is allowing Egypt to export, then he must be confident Egypt will have sufficient production to do so,” says Ellinas.

A question mark, therefore, hangs over the plans for the sale of the relatively small volume of Aphrodite reserves to Egypt. If there was no urgency for Egypt to access these when the country was short of gas, it is hard to see the Cairo authorities making the project a priority today.

Get LNG going

Ellinas considers the Aphrodite plan a distraction. “Cyprus should start developing LNG now and not wait. If Aphrodite gas was sold to Egypt, it would delay things another two-to-three years. And the longer you leave it, the more difficult it becomes. ExxonMobil has mega-projects elsewhere. Just because they made a discovery in Cyprus, it isn’t a game-changer for them.”

As for the idea of a pipeline to take East Med gas to Europe, Ellinas says it simply is not commercially viable. “To produce gas in Israel costs $4-5/mn Btu. By the time you add on pipeline costs and a profit, it is arriving in Europe at $8-9/mn Btu. Gazprom can deliver gas to Europe at a profit at $4.50/mn Btu. Even US LNG is finding it difficult. It is a very competitive market.”

So, with geopolitics keeping the vast and hungry Turkish market next door off limits, it could well be LNG or nothing for Cyprus’ offshore gas finds.

Some analysts say Cyprus could become an East Med energy hub. Others, more realistically, see Egypt taking that role, leaving Cyprus as a regional service centre. But even the more limited goal will not be met, companies say, if they are not allowed more space to operate.

The Cypriot government has approved the development of Vasilikos, the site of the proposed LNG plant on the southern coast, as a dedicated energy port. But this will not be ready until 2023. Until then, energy sector companies will share space at the island’s main commercial port, Limassol. And it is proving to be a tight fit.

Alessandro Barberis, managing director of Eni Cyprus, says “currently, we as operators are forced to use the only oil and gas space available, at Limassol port. It is not enough if simultaneous drilling operations are under way. The Vasilikos port project is targeted for 2023, but we need to think of the medium term.” Dalio Vitale of Halliburton agrees: “Vasiliko is important, but it’s five years away. We need something in the shorter term.

Varnavas Theodossiou, head of ExxonMobil in Cyprus praises the island’s stable investment climate, well-defined legal system and robust tax regime. But he, too, is frustrated by the cramped working conditions. “Maybe Cyprus can expand Limassol port, maybe we can use Larnaca,” he says. “But the current port situation is not sustainable for operators.”

In the view of Yves Grosjean, general manager of Total, Cyprus should put aside any notion of becoming an energy hub — that would take five-to-10 years to achieve. “However,” he adds, “when we talk about an oil and gas service centre we are talking about an urgent need that won’t go away.” Space is needed without delay because “in some cases there are up to 20 different companies working with one operator for drilling one well”.

Jorgen Berg managing director of Schlumberger Cyprus, says it is “important to assess the needs of the industry, and certainly a port is one of those needs. If the issue is not addressed adequately, then “we as operators will follow our own interests elsewhere”. Other deep-water ports such as Malta could fit the bill. Cyprus’ “advantageous position will not last for ever”. As it is, the lack of space seems certain to slow down IOCs’ drilling schedules, with Eni-Total planning five wells at the end of this year, ExxonMobil two next year. It is hard not to see a queue forming at Limassol port.

Once again, the International Monetary Fund (IMF) has made outlandish and inaccurate claims that Saudi Arabia needs—absolutely NEEDS—to push the price of oil higher to fund its government. This time, the IMF claims Saudi Arabia needs the price of Brent to be at least $85 per barrel. The problem with this claim is that it inaccurately implies that Saudi Arabia must work to achieve higher oil prices. However, this isn’t true and Saudi Arabia does not base its oil policy on the budgetary break-even price per barrel of oil.

In September, the IMF forecast that Saudi Arabia needed $73 per barrel. Back in the fall of 2017, I explained the faults in IMF logic when it claimed that Saudi Arabia needed $70 per barrel oil to balance its budget. Among the misunderstandings underlying the IMF calculations, I highlighted that:

1. Aramco oil revenue and Saudi revenue from Saudi Aramco are not interchangeable
2.  The 2017 IMF forecast seemed to ignore the tax rate on Aramco
3. Aramco has the lowest cost of production
4. Saudi Arabia had—and still has—significant cash reserves
5. The Saudi government is trying to spend less on welfare expenses
6. Saudi Arabia has easy access to cheap debt
7. There is nothing wrong with Saudi Arabia running a deficit, especially while interest rates are relatively low
8. Historically, Saudi Arabia has sought to maintain reasonable oil prices instead of prioritizing only high prices, because high oil prices lead to global recessions which depress oil demand

Now, we know even more about Saudi oil revenue and how it is determined. When Aramco released a bond prospectus at the start of April, we learned many of the company and the kingdom’s financial secrets. Among them, we learned that the government funds about 63% of its budget from Aramco through a mixture of income tax (at a 50% rate), royalties (a marginal rate) and dividend. The royalties depend on the amount of oil produced and the price of Brent. The income tax is largely impacted by the price of oil as well. However, the dividend is adjusted quarterly.

Essentially, the dividend is used as a quarterly check to the government to cover whatever the government needs after Aramco’s income taxes and royalties and after the government’s other sources of revenue. In the first quarter of 2019, the government miscalculated how much it needed in dividend and took too much from Aramco. This lead to a $7.41 billion surplus for the government in Q1 2019, despite oil prices that ranged from $54 to $69. Clearly, in Q1 the Saudi government did not NEED $85 oil.

Climate change may be a key issue influencing the outcome of the four-day European Parliament election, which begins on May 23.
A recent opinion poll showed that up to 77% of potential voters identified global warming as an “important criterion” when deciding who to vote for at the election.
The survey by ‘Ipsos MORI’ revealed how much climate change has climbed up on the priority list of European voters. The aim of the survey was to understand the importance of environmental issues in election.
Millions of youngsters marched across European cities over the last months to demand stronger action from politicians on climate change, part of a movement which mobilised millions more worldwide.
“Many young people are going to vote in the elections for the first time and are likely to choose MEPs who support more climate action,” said Wendel Trio, director of Climate Action Network Europe, an environmental organisation.
“This could bring about real change in the future European institutions,” he predicted.
But the violent protests against the carbon tax in France are also a reminder that climate policies can bite back on policymakers if they are not accompanied by social measures to lessen the impact on the poorest.
The survey revealed some common trends among countries. The impact of high electricity and gas prices, for instance, was identified as the top environmental priority in Poland (86%), Spain (88%), and Belgium (82%).
But the single most important environmental issue for voters is to produce food in a healthy, sustainable way. This was rated as the top issue in Slovakia (87%), Austria (86%), Italy (85%) and France (81%) – with an average rating of 82% across the 11 countries surveyed.
There are national divergences too. In Spain for example, voters consider solar energy as an important election topic, while Slovaks also mention wind power.
Meanwhile, French respondents tended to identify organic farming and pesticides as their top environmental concern.
A total of 751 Members of the European Parliament (MEPs) currently represent more than 512mn people from some 28 EU member states.
In February 2018, the European Parliament voted to decrease the number of MEPs from 751 to 705, if the United Kingdom were to withdraw from the European Union on March 29 this year.
However after an extension of the Article 50 process, the United Kingdom is now due to participate alongside other EU member states.
The UK is due to leave the EU on October 31, after Brexit was delayed, amid continuing parliamentary deadlock.
It means the UK must now hold European elections on May 23, or leave on June 1 without a deal.
Every five years, EU countries go to the polls to elect members of the European Parliament. The European Parliament is directly elected by EU voters.
Each country is allocated a set number of seats, roughly depending on the size of its population. The smallest, Malta (population: around half a million) has six members sitting in the European Parliament while the largest, Germany (population: 82mn) has 96.

Turkey’s sovereign wealth fund bolstered the capital ratios of five state-owned banks by €3.3bn ($3.7bn) in a bid to keep credit flowing in the economy.

A market stability fund within the government-controlled investor bought debt issued by the lenders under a recapitalisation programme announced on Monday, which will see a further €400mn flow to Islamic banks.

The Turkish administration is seeking to rekindle growth with cheap loans, while tasking the firms with salvaging industries and helping consumers in the hopes that private firms will follow.

State-owned lenders rushed to extend loans before municipal elections at the end of March as their commercial and international peers pulled back. That helped increase their market share by 3 percentage points to 43% between August and the end of February, according to data compiled by Bloomberg.

TC Ziraat Bankasi AS, the country’s biggest lender, received the most, selling €1.4bn of bonds.

Turkiye Halk Bankasi AS signed an agreement with the fund for a five-year loan of €900mn, the first interest payment of which will be made at maturity. That will improve Halkbank’s Tier 1 ratio by 210 basis points, which is “more than sufficient” to keep it above minimum thresholds, Ates Buldur, a banking analyst at Credit Suisse Group AG’s Istanbul unit, said.

The fund invested in Turkiye Vakiflar Bankasi TAO’s issuance of €700mn of five-year subordinated bonds. Vakifbank bonds have 5.076% coupon rate, although the Treasury earlier said they would have a zero-coupon.

Development bank Turkiye Kalkinma ve Yatirim Bankasi AS, which is being restructured, and Turkiye Ihracat Kredi Bankasi AS, also known as Eximbank, signed agreements for five-year subordinated loans of €150mn each.

Under the plan, the Treasury issues special-purpose government bonds to the stability fund, which then sells the notes to state lenders in exchange for subordinated debt. Islamic lenders Ziraat Katilim, Vakif Katilim and Emlak Katilim will also get funding.

Capital ratios have fallen as the country’s lenders have undertaken nearly $28bns in debt-restructuring requests. They’re also facing a growing pile of bad loans in the wake of the currency’s plunge last year, which has spurred inflation and increased funding costs. The government last year recapitalized three of its banks by selling bonds to its unemployment fund.

OPEC+ states including Saudi Arabia are complying with the terms of the agreement to limit oil output, Russian President Vladimir Putin said.

“We have agreements within the OPEC+. We fulfill our agreements and we don’t have any news, any information, from our Saudi partners and any other OPEC member, that they are ready to exit these agreements,” Putin told reporters in Beijing on Saturday, where he participated in the Belt and Road forum.

On Friday, U.S. President Donald Trump tweeted that he “spoke to Saudi Arabia and others about increasing oil flow” and said that “all are in agreement” after the administration announced on Monday that it wouldn’t extend waivers for buyers of Iranian crude that had allowed them to continue purchases despite American sanctions.

Asked about Saudi Arabia possibly compensating for shortfalls of Iranian oil on the global market, Putin said he hoped that wouldn’t happen and reiterated that countries should abide by the OPEC+ agreement.

The waivers expire on May 2 and China, India, Japan, South Korea, Italy, Greece, Turkey and Taiwan now face the prospect of having to find alternative supplies.

‘Colossal Potential’

“We can produce even more,” Putin said. “We have colossal potential, but it’s not about potential, it’s about the fact that we have agreements with OPEC that we keep to a certain level of output.”

It’s unlikely that Saudi Arabia will abandon the OPEC+ pact that was reached in December and runs to the end of June, since it initiated the deal, Putin said. Russia joined the OPEC+ cooperation because a “coordinated price policy” was needed on the market, he said.

The Russian leader said he discussed the issue of contaminated oil in the Druzhba pipeline to Europe with Belarusian President Alexander Lukashenko. Transneft is investigating how the crude came to be contaminated and law enforcement may become involved if necessary, Putin said.

He told reporters that Russia’s Arctic LNG 2 project won’t affect pipeline gas supplies to China, which wants Russia to increase deliveries via the Power of Siberia link. Russia wants to increase LNG supplies to the world market to 100 million tons, he said.

MOSCOW/DUBAI (Reuters) – Japan’s Mitsui & Co Ltd (8031.T), Russian sovereign wealth fund RDIF and Saudi Aramco are in talks to buy stakes in Novatek’s (NVTK.MM) Arctic LNG 2 project, with the size of the investments still to be decided, sources familiar with the talks told Reuters.

Novatek plans to start producing LNG at Arctic LNG 2 in 2022-2023. The plant, which is expected to cost around $25.5 billion, will have an annual production capacity of 19.8 million tonnes and will be Novatek’s second LNG plant after Yamal LNG.

Novatek owns a 90 percent stake in the project, with France’s Total (TOTF.PA) holding the other 10 percent. Novatek intends to keep a 60 percent stake in Arctic LNG 2, offering 30 percent to other investors.

However, under certain conditions Novatek may cut its stake further, although not to below 50 percent in order to keep control over the project.

Two sources familiar with the talks said that Mitsui, Saudi Aramco and the Russian Direct Investment Fund are in talks with Novatek over taking stakes in the project, which should bring the Russian gas company closer to its goal of producing as much LNG as Qatar, one of the world’s top LNG suppliers.

“Mitsui, Saudi Aramco and RDIF are interested to buy a stake in Arctic LNG 2 but there is also an interest from South Asia,” one of the sources said.

Japan is the world’s top LNG consumer, with Russia among its key LNG suppliers. There are currently two LNG plants operating in Russia: Novatek’s Yamal LNG and Gazprom’s Sakhalin 2 and Moscow has ambitions for more.

A third source confirmed Mitsui’s interest in the project. Three other sources familiar with the talks confirmed the interest from Saudi Aramco and RDIF.

“Saudi Aramco is currently holding technical due-diligence. When the commercial talks approach, RDIF will join(in),” one of the three sources familiar with the talks said.

While RDIF will invest in the project, its contribution is likely to be less than Aramco’s, the second of the three sources familiar with the talks told Reuters.

Talks between Mitsui and Novatek are separate from talks with Saudi Aramco and RDIF, sources said. Each would have a stake in Arctic LNG 2 if their talks succeed, according to the sources.

Saudi Aramco declined to comment and Novatek could not immediately respond to a Reuters request for a comment on Friday. RDIF declined to comment.

“We have a general interest in the project and we are exchanging our opinions with parties involved,” a Mitsui spokesman said when asked whether the company planned to invest in the project.

This week, Novatek awarded a 2.2 billion euro ($2.51 billion) contract to Italian energy contractor Saipem (SPMI.MI) and Turkish oil and gas services firm Renaissance for the construction of gravity-based structure platforms that will stand on the seabed to support the LNG processing units.

($1 = 0.8749 euros)

Six months after the U.S. rocked oil markets by letting Iranian exports continue, its decision to end sanctions waivers that allowed shipments is also set to reverberate across the globe.

The U.S. is said to announce Monday morning in Washington that it won’t renew exemptions from its sanctions to buyers of Iranian crude after they expire on May 2. It marks a change in direction from November last year, when the Donald Trump administration granted waivers to eight importers as it sought to temper fuel prices ahead of American mid-term elections.

The move threatens to squeeze supplies further in a market that’s already facing supply disruptions from Venezuela to Libya and Nigeria, and extend this year’s rally in global benchmark Brent crude above $70 a barrel. Prices are still below the four-year highs of over $86 they hit in October before the U.S. issued its waivers.

What the  waivers allowed: China — oil imports of as much as 360,000 barrels a day India — as much as 300,000 b/d of crude purchases South Korea — 200,000 b/d of condensate, an ultra-light oil Japan — exempted volume unknown; shipping data shows it bought 108,000 b/d that loaded in March Turkey — about 60,000 b/d Taiwan — volume unknown; nation’s refiners said previously they don’t plan to buy anything even with waivers

Here are some of the potential implications of the Trump administration’s latest decision, which is aimed at piling economic pressure on Iran over the Persian Gulf state’s nuclear program by cutting off a key source of the OPEC member’s revenue.

Fate of OPEC+ Deal

The U.S. government will also announce that it got commitments from suppliers such as Saudi Arabia and the United Arab Emirates to offset the loss of Iranian crude, according to people with knowledge of the matter.

That could jeopardize the output deal between the Organization of Petroleum Exporting Countries and its allies, which have been curbing supplies since the start of the year to avert a glut. Russia, one of the partners in the pact, has already signaled that the cuts may not need to be extended. A decision is expected when the producer group known as OPEC+ meets in June.

The pact was driven by Saudi Arabia after it was blindsided last year by the U.S. decision to grant waivers, which sparked a collapse in crude into a bear market in the fourth quarter. Now, the American pledge to eliminate oil exports from Iran may provide an incentive for Crown Prince Mohammed Bin Salman — a Trump ally — to ease the kingdom’s policy.

Price Relief?

While crude has jumped more than 3 percent on the news that the U.S. won’t renew exemptions, the future direction of prices may be determined by how much the likes of Saudi Arabia and the U.A.E. are able to cushion the blow amid other supply disruptions.

Last year, prices jumped to over $86 a barrel even though Saudi Arabia was pumping at record levels. Now, it’s not just Iranian shipments that are disrupted. Separate U.S. sanctions on Venezuela have squeezed supplies from that OPEC producer too, while fellow group member Libya is roiled by violence. Just on Sunday, a key oil pipeline in Nigeria was halted after a fire.

Iran’s exports in March totaled about 1.3 million barrels a day, tanker-tracking data compiled by Bloomberg show. Shipments were as high as 2.5 million barrels daily in April last year, before the U.S. announced plans to reimpose sanctions on the Islamic Republic.

Pain for Buyers

The current set of waivers expiring on May 2 allowed China, India, Japan, South Korea, Italy, Greece, Turkey and Taiwan to continue importing Iranian crude without being subjected to retaliatory U.S. sanctions. With the end of the waivers, the buyers face being cut off from the American financial system if they continue purchases.

Of the buyers, Asian nations India, South Korea, China and Japan are likely to be the hardest hit. If crude prices go higher, the budget deficit in import-dependent nations may also worsen and inflation could accelerate. The biggest importers had already put purchases from the Persian Gulf state on hold as they waited for the U.S. decision.

South Korea’s Hanwha Total Petrochemical Co. has already been buying and testing alternative cargoes from areas such as Africa and Australia. While it’s not impossible to find other options, that would raise costs and could affect the company’s profits, according to a spokesman.

Alternative American

Some buyers may find relief in the shape of rising U.S. shale exports. South Korea, for example, buys a form of ultralight oil known as condensate from Iran, which can potentially be replaced with an alternative from America — though it would mean higher freight costs owing to a longer shipping journey.

But for others, U.S. shipments may not be the best option. That’s because American shale supply is typically made of “light-sweet” varieties that have a relatively low sulfur content and density. The type of crude that’s being squeezed in the market — from Venezuela for instance — are “heavy to medium sour” grades that are more sulfurous and denser.