NEW YORK (Reuters) – Oil prices fell about 1% on Thursday after a media report cast doubt on the possibility of an interim U.S.-China trade deal and as a meeting of the OPEC+ alliance yielded no decision on deepening crude supply cuts.

Oil was pressured further after the European Central Bank cut its deposit rate to a record low -0.5% from -0.4% and said it will restart bond purchases of 20 billion euros a month from November to prop up euro zone growth.

Brent crude LCOc1 futures settled at $60.38 a barrel, shedding 43 cents, or 0.71%. WTI crude CLc1 futures settled at $55.09 a barrel, losing 66 cents, or 1.18%.

Oil futures extended losses after a senior White House official denied a Bloomberg News report that the United States was considering a temporary trade agreement with China, according to CNBC.

Earlier, prices had been supported on news that the world’s two largest economies made some concessions in their protracted trade war.

“We had a lot of moving parts. We came in with the ECB, then we saw the U.S was going to reach some kind of interim agreement with China, then they ended up saying they’re not,” said Phillip Streible, senior commodities strategist at RJO Futures in Chicago. “Now we’re just back-pedaling and cautiously waiting for the next development in the market, whether it be from economic data, more verbiage from OPEC, and we’re still going to monitor inventories as a whole.”

Oil prices also stumbled after comments from Saudi Arabia’s new energy minister, Prince Abdulaziz bin Salman, said deeper cuts would not be decided upon before a meeting of the Organization of the Petroleum Exporting Countries planned for December.

A Thursday meeting of the market-monitoring committee formed by the Organization of the Petroleum Exporting Countries and its allies, whose de facto leader is Saudi Arabia, yielded a promise to keep countries within the production quotas they committed to in a global supply deal.

A statement from OPEC and its allies, a grouping known as OPEC+, said oil stocks in industrial countries remained above the five-year average. Oman’s energy minister said “the outlook is not very good for 2020.”

Prince Abdulaziz said Saudi Arabia would keep cutting by more than it pledged in the pact, which has throttled supply from OPEC+ by 1.2 million barrels per day.

Also feeding the bearish sentiment, the International Energy Agency said surging U.S. output would make balancing the market “daunting” in 2020.

“Booming shale production has allowed the U.S. to close in on, and briefly overtake, Saudi Arabia as the world’s top oil exporter … in June, after crude exports surged above 3 million bpd,” the agency, which advises industrial economies on energy policy, said in its monthly report.

The Paris-based IEA kept its oil demand growth forecasts for this and next year at 1.1 million barrels per day and 1.3 million barrels per day, respectively.

SINGAPORE/BEIJING (Reuters) – China aims to slash its growing dependence on gas imports by boosting domestic projects like shale fields as the security of its energy supply comes under the spotlight amid a festering trade war with the United States.

The row with Washington has overshadowed China’s economy, likely slowing gas demand growth considerably this year, a new government research report shows. But Beijing is funding new efforts to boost domestic production, particularly from so-called unconventional sources like shale gas, as weaning China off its import reliance takes on new importance.

The report, released on Saturday by the oil and gas department at the National Energy Administration (NEA) and a State Council research arm, calls for boosting natural gas production in key resource basins in the southwestern province of Sichuan, the Erdos basin in the north and offshore China.

According to the report, China’s gas consumption will rise by about 10% this year to 310 billion cubic meters (bcm), and to continue growing until 2050. Though slowing from last year’s 17.5%, 2019’s growth still represents an annual addition of 28 bcm, faster than the annual average growth of 19 bcm during 2007-2018, the report said.

While China imposed tariffs on imports of liquefied natural gas (LNG) from the United States starting last year, it remains the world’s second-largest buyer of the super-chilled fuel.

“China’s reliance oil and gas imports is growing too rapidly, with oil topping 70% and gas moving toward 50%,” said Lin Boqiang, Director of the Energy Economics Institute at Xiamen University.

The NEA report calls for building the Sichuan basin into the country’s top gas hub due to its rich resource base in both conventional gas fields and unconventional resources, such as shale gas and ‘tight gas’, a low-permeability gas derived from reservoir rocks and costly to develop.

“Through expanding development of deep-reservoir gas, tight gas and shale gas, Sichuan is likely to account for about a third of the country’s total natural gas output,” the report said, up from 20% currently.

Shale gas in Sichuan, the key region for China’s still fledgling shale gas development, could overtake conventional gas in output, the report added.

SHALE GAS

In a separate report carried by official news agency Xinhua on Saturday, Zhao Wenzhi, an influential researcher at China’s Academy of Engineering forecast that China’s shale gas output could reach 280 bcm, or 23% of the country’s total gas output, by 2035. Zhao also serves as president of Exploration and Production Institute at state giant PetroChina.

China last year produced about 10.9 bcm shale gas, less than 7% of the nation’s total gas output at 161 bcm.

The leap in projected shale gas output would require companies drilling over 500 wells a year between 2019 and 2035, double the 2018 level, Zhao was cited as saying.

Dominant state oil and gas firms have already ramped up drilling activities with near-record spending, in response to a call by President Xi Jinping in August last year to boost domestic energy security.

To expedite the growth, Beijing should consider offering tax sweeteners such as waiving resource tax on the shale gas, Zhao said.

China recently also announced a policy to extend subsidies for another three years on domestic production of unconventional gas, to include also tight gas for the first time.

In a research note last week, Wang Xueke, a consultant at Wood Mackenzie, raised China’s tight gas outlook to 85 bcm by 2040, up from an earlier forecast at 68 bcm.

Despite the lofty forecast and state subsidies, China faces complex geology and a lack of technological breakthroughs to make shale gas a profitable enough business to lure private money.

“The investment is still too small as only a handful state-run companies are exploring it … Technology progress is not fast enough,” said Xiamen University’s Lin.

LONDON (Reuters) – While U.S. sanctions on Iran’s oil industry have slashed the OPEC member’s crude exports by more than 80%, oil product sales from the Islamic Republic remain strong at nearly $500 million a month, shipping data and Reuters calculations show.

Sanctions have barely affected Iran’s exports of oil products, primarily fuel oil used for power generation and shipping as well as liquefied petroleum gas (LPG) used as cooking gas and petrochemical feed.

Iran’s product exports reached their highest level in August, oil minister Bijan Zanganeh was quoted as saying by a lawmaker after a parliamentary meeting on Aug. 27. “In exports of products we have no problem,” Zanganeh was cited as saying.

Consultancy FGE estimates Iran’s product exports at 400,000-500,000 barrels per day, exceeding the top end of crude export estimates by other analysts of some 400,000 bpd for July.

Refinitiv Eikon data shows Iran exported more than 230,000 bpd of fuel oil in August, all to the United Arab Emirates, slightly above July’s figure of 220,000 bpd. At current prices, and assuming Iran is not selling at a big discount, such sales generate over $300 million a month.

Data intelligence firm Kpler says Iran exported 514,000 tonnes of LPG in July, or nearly 200,000 bpd, worth over $180 million at market prices. This compares with 579,000 tonnes in June. China accounted for more than 95% of Iranian LPG exports in June, according to Kpler.

Samantha Hartke, head of natural gas liquids and LPG at consultancy Energy Aspects, said her firm did not expect Chinese imports of Iranian LPG to abate given China’s new petrochemical capacity is creating significant demand for the feedstock.

“The irony is: if not for the U.S.-China trade war, the U.S. would have greatly benefited from this uptick in Chinese demand as a means of mopping up its overabundance of LPG supplies, thanks to shale,” she added.

Unlike crude oil, where the ultimate buyer is a refinery, fuel oil and LPG can find their way to potentially thousands of small-scale industrial or residential buyers, Iman Nasseri, managing director for the Middle East with FGE, told Reuters.

“The market for these two products is so vast that finding and targeting those individuals is not easy,” he said.

In July, Grace 1, a jumbo tanker laden with Iranian crude, became the most-watched ship in the world after the British navy seized it off the coast of Gibraltar on suspicion of carrying oil to Syria.

The tanker has changed its name to the Adrian Daria since being released by Gibraltar and is in the eastern Mediterranean.

Oil products, like crude, fall under U.S. sanctions.

“Non-U.S. persons engaged in this sanctionable conduct could be sanctioned themselves and be subject to blocking by the U.S.,” Erich Ferrari, a Washington-based attorney who specializes in sanctions law, told Reuters.

Iran’s oil ministry did not immediately respond to a Reuters request for comment.

SELF-SUFFICIENCY

Iran has a refining capacity of around 2.23 million bpd, putting it behind regional leader Saudi Arabia. But years of sanctions and underinvestment mean the country’s refining sector lags its Gulf neighbors, who have invested billions of dollars to create some of the world’s most complex refineries.

Despite the challenges, Iran declared self-sufficiency in gasoline after the inauguration of the third phase of its 350,000-bpd Persian Gulf Star refinery in February. Shipping data shows Iran has imported barely any oil product recently.

Iranian gasoline production stands at 105 million liters per day, according to Zanganeh, or around 660,000 bpd, while consumption is around 100,000 bpd below production. It even exported gasoline this year for the first time. Its gasoil production stands at around 720,000 bpd.

Russia’s average daily oil output in August exceeded its Opec+ cap for the  first time since April as the impact of the Druzhba contamination crisis faded. The country pumped 47.8mn tonnes of crude and condensate last month, according to preliminary data from the Energy Minis- try’s CDU-TEK unit. That implies a daily average of 11.294mn barrels – based on the standard 7.33 barrels-per-tonne conversion ratio – and is 104,000 barrels a day above its Opec+ target, Bloomberg calculations show. Russia’s compliance with pledged production cuts has retreated just weeks before Opec+ ministers meet in Abu Dhabi to discuss the implementation of their accord to curb output. The Organisation of Petroleum Exporting Countries and its allies agreed in July to extend their pact into 2020. Under the deal, Russia committed to cut output by 228,000 barrels a day from October levels. The nation reduced oil production more steeply than required in the three months through July, after the discovery of contaminated crude in the Druzhba pipeline forced parts of the link to shut down. Energy Minister Alexander Novak signaled last week that August compliance would be lower, given the deep cuts made previously, Interfax reported. Opec and its partners, a 24-nation coalition known as Opec+, agreed to reduce output by 1.2mn barrels a day at the beginning of 2019 as a faltering global economy and booming US shale-oil production threatened to leave world markets with a glut.

Opec’s crude production rose last month, the first increase since the group and its allies started a new round of output cutbacks at the start of the year to shore up a weak global market.
Nigeria and Saudi Arabia led the boost by the Organisation of Petroleum Exporting Countries, which collectively increased by 200,000 barrels a day to 29.99mn a day, according to a Bloomberg survey. The survey is based on estimates from officials, ship-tracking data and consultants including Rystad Energy and JBC Energy GmbH.
Opec and its partners, a 24-nation coalition known as Opec+, agreed to reduce output by 1.2mn barrels a day at the beginning of 2019 as a faltering global economy and booming US shale-oil production threatened to leave world markets with a glut. That deal replaced a previous round of curbs that began in January 2017.
The strategy has struggled to shore up prices against a deteriorating outlook for global growth and a seemingly intractable trade war between the US and China. Brent futures have subsided more than 20% from a peak reached in April and traded near $59 a barrel yesterday.
Riyadh boosted output by 50,000 barrels a day to 9.83mn a day in August, a time when domestic consumption typically climbs amid soaring use of air conditioning.
Nigeria hasn’t made any of the cuts it pledged, and increased output again in August, by 60,000 barrels a day to 1.95mn, the highest level since early 2016. The West African producer has ramped up production to maximum levels at its new Egina offshore oil field operated by Total SA, according to the International Energy Agency.
Russia, the biggest producer outside Opec in the coalition, has also shown signs of backsliding on its commitments.
The country pumped 11.294mn barrels a day in August, or 104,000 a day more than its limit under the Opec accord. Energy Minister Alexander Novak had signalled compliance would slide as Russia cut more than required earlier this year following the discovery of contaminated crude in its Druzhba pipeline.
A committee made up of key members in the Opec+ alliance will meet in Abu Dhabi on September 12 to review their progress in stabilising world crude markets. The full coalition will then gather in December in Vienna to consider any action required in 2020.

DEFA announced on 23 August its decision to award the tender for the construction of an LNG import terminal at Vasilikos. This will comprise a floating storage regasification unit (FSRU), a jetty for the mooring of the FSRU, pipelines, port and other facilities.

The winner is a consortium comprising China Petroleum Pipeline Engineering Co Ltd (CPPE), Aktor SA and Metron SA, Hudong-Zhonghua Shipbuilding Co. Ltd and Wilhelmsen Ship Management Ltd.

Announcing its decision DEFA said “we believe that the future of the country is aligned with natural gas and we expect it to play a major role in the economic development of the country in years to come.

“The establishment of the natural gas market will boost the development of the whole energy and industry sectors of the Republic.”

Indeed, natural gas can help bring carbon emissions down. In order to produce the same energy output gas emits about 27 per cent less carbon dioxide in comparison to diesel oil. As a result, replacing diesel by gas in power generation will be helpful, at least initially. I say initially, because the EU’s target is to reduce emissions by 40 per cent by 2030 in comparison to 1990 levels.

The challenge for Cyprus is that so far it has been promising small reductions to its CO2 emissions in comparison to 2005, when these were close to their peak – about 60 per cent higher in comparison to 1990 according to Eurostat data. By the end of 2017 Cyprus’ emissions were only marginally lower than in 2005.

In fact the incoming European Commission (EC) President, Ursula von der Layen, promised to increase EU’s 2030 CO2 reduction target to 50 per cent. In addition, the EC has already sent back Cyprus’ Energy Plan to 2030 for not being ambitious enough and requested it to be revised nearer EU targets.

With no other change, and with power generation being only 20 per cent of Cyprus’ total energy consumption, introduction of LNG will reduce carbon emissions only by 8 per cent in comparison to 2005 and close to 50 per cent higher than in 1990. A modest but useful reduction, but it will not get close to EU expectations for 2030. Cyprus will need to do a lot more to achieve that – by substantially increasing use of renewables and biofuels.

Impact on electricity costs

When asked about cost implications, DEFA said that state ownership of the project will allow the cost of importing and regasifying LNG to be kept sufficiently low to keep the cost of gas offered to EAC below $10/mmBTU (per about 1000 cubic feet) – the equivalent cost of oil at current prices.

DEFA was also asked how can Cyprus commit itself to expensive infrastructure when it does not yet know whether it can secure gas at an affordable price. The response was that that even if the ongoing process – in response to the request for expressions of interest for the long-term supply of LNG for 10-20 years – does not produce favourable prices, DEFA’s needs can be met in the short-term by the spot market, which with today’s prices can provide LNG at $3-$4/mmBTU.

Indeed, as a result of excessive supplies of LNG, spot gas prices in Europe are currently at a low, at about $4/mmbtu. However, in October 2018 they were about $10/mmbtu. But by 2022 – the time at which Cyprus will be ready to import LNG – demand is expected to exceed supply, with prices rising again. Available forecasts estimate the price of gas in Europe to average about $6.50/mmbtu in the ten-year period to 2030.

Given the small quantities required by Cyprus – initially about 0.5 million tonnes LNG per year – the spot price for LNG to be delivered to Cyprus is expected to be higher. Adding to this the recovery of the cost of constructing the facilities (allowing for the EU grant), operation and maintenance – and other related costs and costs incurred by EAC – is likely to bring the total cost above the $10/mmbtu level. Long-term supply contracts would cost even more.

What is amazing is that the decision to proceed with award of the construction contract appears to have been taken without first securing LNG at reasonable prices and without a commercial viability study based on expected, reliable, LNG costs.

Other issues

DEFA expects to finalise award of the construction contract by mid-October, with the facilities becoming operational by the end of 2021.

But there may be complications. First, its decision to award the tender to the CPPE consortium, taken after a short evaluation period of six weeks, may be disputed by other bidders, which may cause delays.

It should be noted that the unsuccessful consortia are well known, experienced companies, in the global LNG industry. In contrast, CPPE, the leader of the winning consortium, has no real LNG experience.

There are also questions about members of the winning consortium. Aktor SA is the sister company of Helector, facing corruption charges related to HYTY Paphos. Aktor SA had accusations leveled against it for fraud related to projects in the Balkans. Both companies are fully-owned by Greece’s Ellaktor Group. These and other questions will hopefully be cleared during the period before final award, but could, nevertheless, cause months of delays.

Will gas boost Cyprus economy?

Given the above, this is not certain. Gas could boost industry and benefit the economy if its introduction leads to substantial cost reductions in comparison to diesel. But this may not be the case. In fact it could be the opposite.

Import of gas by pipeline, either directly from Aphrodite or by accepting Energean’s offer to supply gas from its gas-fields in Israel, could do exactly that, with gas prices to EAC less than $7/mmbtu. Sadly these options have not been taken on.

Moreover, gas alone will not reduce carbon emissions to the levels required by the EU. This would require a substantial increase in the share of renewables and biofuels in Cyprus energy mix.

Without properly and transparently demonstrating the commercial viability of the project – based on reliable data – Cyprus runs the risk of being trapped into an expensive undertaking for at least the next ten years. Not only this may not boost industry, but may also become a long-term burden to Cyprus’ economy.

Dr Charles Ellinas (@CharlesEllinas) is a senior fellow at Global Energy Centre of the Atlantic Council

American oil explorers, which are producing record volumes of crude, cut drilling to a 19-month low as they seek to show investors they can do more with less. Working oil rigs fell by 12 last week to 742, according to data released on Friday by oilfi eld-services provider Baker Hughes. The count has dropped by more than 140 from a November high. In the Permian Basin, 5 rigs were idled, lower- ing the count there to 429. As explorers dial back spending, Bank of America Merrill Lynch downgraded a trio of shale servicers this week, including Na- bors Industries Ltd, owner of the world’s biggest fl eet of land drilling equipment. “For US onshore, structural changes are accelerating,” Chase Mulvehill, an analyst at Bank of America Merrill Lynch, wrote last week in a note to investors. “Doing more with less remains prevalent across US shale, leaving a destructive impact on US onshore activity that is likely to extend well into ’20 (or beyond).” Despite the rig-count decline this year, US crude production keeps increasing. It rose to a record 12.5mn barrels a day last week, eclipsing the previous high mark set in late May, according data from the Energy Information Administration. That’s partly because producers have an ample backlog of wells that have already been drilled in the past and can be tapped for fracking, but they are also seeking bet- ter technology to get more crude from each hole. Plus, it may take a few more months for output from wells bored during last year’s drilling peak to start declining.

Bloomberg /London: September 02 2019 12:38 AM

Big Oil has a new contender for the No 2 spot. Chevron Corp has almost displaced Royal Dutch Shell Plc as the second-largest oil company by market capitalisation.

It’s been a particularly grim month for Big Oil, as a US-China trade war dimmed the picture for global economic growth, stymieing crude demand. The Stoxx Europe 600 Oil & Gas Index was headed for a 6.3% decline, among the largest monthly drops in nearly four years, which mirrors the slide in Brent prices.

But Shell had it worst. Its B shares in London have plunged more than 12% last month, a decline not seen since the 2008 financial crisis, which has knocked almost £26bn ($32bn) off its market value. That’s put chief executive officer Ben van Beurden’s dream of being No 1 in the industry by every measure even further out of reach.

Shell established itself as the No 2 oil company following its acquisition of BG Group Plc, narrowing its market cap gap with Exxon Mobil Corp. But its US competitor Chevron has now caught up with it again.

Blame earnings. Shell’s net income slid in the second quarter and was far weaker than expected, falling short of the average analyst estimate by almost 30%. That was its biggest miss in more than two years, and pushed chief financial officer Jessica Uhl to acknowledge the company should probably find a way to better manage expectations.

“Shell’s shares have suffered from an unwelcome relapse of earnings volatility,” said Christyan Malek, head of European oil and gas research at JP Morgan Chase & Co. “While we view this as more of a bump in the road, together with the oil price correction – which Shell is more geared to – it has under-performed more than others.”

Chevron, on the other hand, surpassed second-quarter analyst estimates by 21%. Its shares still fell in August, along with the rest of the industry, but its dip was only a third of Shell’s. It’s also traded in dollars, an advantage over sterling-denominated Shell B shares. The British currency has been pummelled by the Brexit process.

Both companies still trail Exxon by a large margin. The Irving, Texas-based oil giant’s market cap is almost $290bn, compared to Chevron and Shell’s $223bn.

If you take a drive along the well-worn highways of West Texas, orange flames will punctuate your journey. Those are gas flares, and they’re lighting up the skies above West Texas oilfields like never before as drillers produce crude faster than pipes can be laid to haul the attendant natural gas away. Oil drillers say flaring is the most environmentally friendly way to get rid of excess gas they can’t sell. Environmentalists say that in many cases what flaring is friendly to is oil drillers’ profits. They think regulators in states including Texas and North Dakota should be tougher on a practice that harms air quality and contributes to climate change.

1. Why do drillers flare?

When an oil well begins to spew, less-valuable natural gas comes up alongside crude. Pipelines can capture that gas, but when they’re not available, producers often get rid of the gas so they don’t have to stop pumping oil. They do that by either igniting the gas, in the case of flaring, or releasing it directly into air, known as venting. Flaring is preferred because methane, an especially potent greenhouse gas, is burned off, though carbon dioxide is released into the air.

2. How much gas is flared?

A lot. The World Bank estimated that globally in 2018, 145 billion cubic meters of gas was flared, about as much as Central and South America use in a year. The amount is rising because of the oil boom in the U.S., which is fueled by the use of hydraulic fracturing — fracking — to unlock fuel from shale rock. Increased flaring in the U.S. is concentrated in the shale oil basins known as the Eagle Ford in Texas, the Permian in Texas and New Mexico, and the Bakken in North Dakota. Permian flaring rose about 85% last year, according to data from Oslo-based consultant Rystad Energy. The volume flared in Texas by the end of 2018 was greater than residential gas demand in the entire state.

3. What are the effects?

Gas flaring globally emits more than 350 million tons of carbon dioxide in a year, according to the World Bank. That’s the equivalent of the carbon emissions from 90 coal-fired power plants. In the U.S., flaring accounts for an estimated 9% of the greenhouse gas emissions of the oil and gas industry. In addition, the practice spews particulate matter, soot and toxins into the air that have been shown to be hazardous to humans.

4. How does the U.S. regulate flaring?

Flaring is allowed when the gas could cause a safety concern due to high pressure in a well and when pipelines aren’t in place to carry the fuel away. In either case, flaring spares drillers from having to suspend production, a costly move that can damage a reservoir’s future output. The Texas Railroad Commission, the main oil and gas regulator in the state, has never denied a request for a flaring permit. In a controversial case, it granted one Aug. 6 to Exco Resources Inc. even though the company’s wells were already connected to pipelines. Exco successfully argued that it would lose money paying to access the network.

5. Isn’t the gas worth something?

The short answer is no, not in oil-dominated basins where what matters is the ability to keep pumping black gold. In the Permian, local gas prices have gone negative multiple times this year, meaning drillers were actually paying customers to haul their gas.

6. Will more pipelines help?

Yes, when prices justify the costs of capturing the gas and transporting it to markets. A new pipeline led by Kinder Morgan Inc. is expected to reduce the pressure to flare. At the same time, pipeline projects in Texas are beginning to attract public opposition, a more common phenomenon in the northeastern U.S. Landowners along the route of another Kinder Morgan line are fighting the project in court, arguing against the company’s use of eminent domain to take private property. It’s not clear whether the legal battle will affect the project, but the challenge portends a tone shift in a historically industry-friendly state.

7. Are there alternatives to flaring?

Apart from transporting gas to markets via pipeline, oil producers can use it on-site as an energy source or reinject it underground. Both options require investments, however. Russia requires oil drillers to make use of 95% of the gas they produce, while Nigeria prohibits flaring, yet the practice is common in both places. That suggests bans may not be sufficient without incentives to curb flaring.

To contact the reporters on this story: Ryan Collins in Houston at rcollins74@bloomberg.net;Rachel Adams-Heard in Houston at radamsheard@bloomberg.net

To contact the editors responsible for this story: Simon Casey at scasey4@bloomberg.net, Lisa Beyer

©2019 Bloomberg L.P.

DUBAI (Reuters) – A senior Iranian official said on Saturday the United States had shown flexibility on the licensing of Iranian oil sales and this was a sign that Washington’s “maximum pressure” policy against Tehran had been defeated, state media reported.

French President Emmanuel Macron paved the way at a G7 summit a week ago for a potential diplomatic solution to a confrontation between the United States and Iran brewing since President Donald Trump withdrew Washington last year from world powers’ 2015 nuclear deal with Tehran.

“Macron met with …Trump during the G7 meeting and the U.S. side has shown some flexibility in the licensing of Iranian oil sales,” Iranian Deputy Foreign Minister Abbas Araqchi was quoted by the state news agency IRNA as saying.

“This is a breach in the U.S. maximum pressure policy and a success for Iran’s policy of maximum resistance,” he said.

Araqchi did not elaborate, and there was no immediate French or U.S. comment.

Since ditching the nuclear deal, calling it flawed to Iran’s advantage, Trump has reimposed sanctions to strangle its vital oil trade and force Tehran to accept stricter limits on its nuclear activity, curb its ballistic missile program and end its support for proxy forces around the Middle East.

Araqchi said Iran and its European partners in the nuclear deal faced “difficult and complex” talks towards salvaging the pact. He said Tehran was determined to continue reducing its commitments under the accord until it received protection against sanctions on its oil sales and banking transactions.

Iranian President Hassan Rouhani urged his people on Wednesday to unite to overcome Washington’s “economic war” while his government said it would use diplomacy to try to solve the standoff even though it distrusted Trump.

IRANIAN TANKER BLACKLISTED

On Friday, the U.S. Treasury Department blacklisted the Iranian oil tanker Adrian Darya, with Secretary of State Mike Pompeo saying Washington had reliable information the vessel was headed to Syria, an ally of Tehran.

The ship was detained by Britain off Gibraltar in July due to suspicions it was carrying Iranian oil to Syria in violation of European Union sanctions. It was released in mid-August after Iran gave assurances that its cargo was not destined for Syria.

Turkey said on Friday the ship was headed to Lebanese waters after changing course several times. Beirut said it was not informed of the plan, but Turkey’s information suggested that a ship-to-ship transfer of cargo might be attempted once it nears the coast of Lebanon, which borders on Syria.

A senior Iranian military commander vowed that Iran would retaliate if any of its vessels was stopped in international waters, according to Fars news agency.

“Piracy against Iran can’t be easily overlooked. It is natural for us to act when Iranian ships are stopped in any part of the world’s waters. Iran’s armed forces will certainly retaliate,” Brigadier General Kiumars Heydari, the head of Iran’s regular ground forces, told Fars.