MOSCOW (Reuters) – Russian state oil major Rosneft has become the main trader of Venezuelan crude, shipping oil to buyers in China and India and helping Caracas offset the loss of traditional dealers who are avoiding it for fear of breaching U.S. sanctions.

Trading sources and Refinitiv Eikon data showed Rosneft became the biggest buyer of Venezuelan crude in July and the first half of August.

It took 40% of state oil company PDVSA’s exports in July and 66% so far in August, according to the firm’s export programs and the Refinitiv Eikon data, double the purchases before sanctions.

Three industry sources said Rosneft, which produces around five percent of the world’s oil, is now taking care of shipping and marketing operations for the bulk of Venezuelan oil exports, ensuring that PDVSA can continue to supply buyers.

Rosneft used to resell volumes it bought from PDVSA to trading firms and was less involved in marketing.

Now it has started supplying some PDVSA clients – Chinese and Indian refineries – while trading houses such as Swiss-based Trafigura and Vitol have walked away because they fear they could breach secondary U.S. sanctions, according to six trade sources.

Trafigura and Vitol declined to comment.

Rosneft and PDVSA did no respond to requests for comment.

Oil accounts for more than 95 percent of Venezuela’s export revenue and Washington has warned trading houses and other buyers about possible sanctions if they prop up Caracas.

The United States and some Western governments have recognized Venezuelan opposition leader Juan Guaido as the country’s rightful head of state and are seeking to oust the current socialist President Nicolas Maduro.

A State Department spokesman said the United States “has put foreign institutions on notice that they will face sanctions for being involved in facilitating illegitimate transactions that benefit … Maduro and his corrupt network.

“We will continue to use the full weight of U.S. economic and diplomatic power to complete the peaceful transition to a once-again free, prosperous and stable Venezuela.”

Moscow is one of Maduro’s closest allies and has provided military support to his government as well as billions of dollars in loans and equipment.

“Rosneft has been dealing with Venezuela’s crude directly, fixing vessels and offering it to end users”, a source with an oil trading firm said.

Rosneft is not in breach of U.S. sanctions, because it takes oil as part of debt servicing agreements after lending Caracas money in previous years.

PDVSA lowered its outstanding debt to Rosneft to $1.1 billion by the end of the second quarter this year from $1.8 billion at the end of the first, the Russian company said on Wednesday.

The sources said most deals between the two do not involve cash. Those that do are processed in euros rather than in U.S. dollars to cover Venezuela’s debt to Rosneft.

Russia and China have called U.S. sanctions against Venezuela unilateral and illegal.

Last week, Washington imposed new sanctions on Venezuela, threatening to take measures against any firm “materially assisting” Maduro’s government.

SUPERTANKERS TO ASIA

According to PDVSA’s loading export schedules, Rosneft has chartered four super-tankers (very large crude carriers or VLCCs) and three smaller Suezmax tankers for Venezuelan crude oil loadings in the first half of August.

All operations are being conducted by Rosneft’s trading office in Geneva, according to three trading sources.

Rosneft has been selling Venezuelan crude to two main destinations – China and India – according to the sources, PDVSA’s loading data and Eikon Refinitiv shipping data.

Rosneft delivered two super-tankers with 280,000 tonnes of oil each to Shandong in eastern China in July and August, and the oil went to an independent refinery, according to Refinitiv crude analyst Emma Li and two trading executives.

This is unusual, because oil has been imported only by state giant Petrochina under term contracts with PDVSA.

Rosneft delivered a separate cargo of 140,000 tonnes to a state-run oil firm, also to Shandong, in mid-August, Refinitiv’s Li said.

The new sales came after Rosneft stepped up marketing efforts in May. It visited several independent refiners in Shandong, said a purchasing executive with one independent refiner who met Rosneft officials.

Rosneft has also become an active supplier of Venezuelan crude oil to India. The company has increased Venezuelan oil sales to India’s refiners Nayara Energy, which it partly co-owns, and Reliance this year. As a result the refiners decreased direct purchases from PDVSA.

Nayara Energy and Reliance declined to comment.

According to data from OPEC, Venezuelan oil output has collapsed to around 0.7-1.0 million barrels per day (bpd) from as much as 3 million at the turn of the century due to a lack of investments and sanctions.

The United States, India and China were Venezuela’s biggest customers prior to the sanctions.

(Bloomberg) — A looming U.S. sanctions deadline is threatening to clobber Venezuela’s dwindling oil-rig fleet and hamper energy production in the nation with the world’s largest crude reserves.

Almost half the rigs operating in Venezuela will shut down by Oct. 25 if the Trump administration doesn’t extend a 90-day waiver from its sanctions, according to data compiled from consultancy Caracas Capital Markets. That could further cripple the OPEC member’s production because the structures are needed to drill new wells crucial for even maintaining output, which is already near the lowest level since the 1940s.

A shutdown in the rigs will also put pressure on Nicolas Maduro’s administration, which counts oil revenues as its main lifeline. The U.S. is betting on increased economic pressure to oust the regime and bring fresh elections to the crisis-torn nation, a founding member of the Organization of Petroleum Exporting Countries and Latin America’s biggest crude exporter until recent years.

Venezuela had 23 oil rigs drilling in July, down from 49 just two years ago, data compiled by Baker Hughes show. Ten of those are exposed to U.S. sanctions, according to calculations by Caracas Capital Markets. The Treasury Department extended waivers in July for service providers to continue for three more months, less than the six months the companies had sought.

Most other government agencies involved in the deliberations opposed any extension, a senior administration official said last month, adding that another reprieve will be harder to come by.

“Almost half the rigs are being run by the Yanks, and if the window shuts down on this in two months, then that’s really going to hurt Venezuela unless the Russians and the Chinese come in,” said Russ Dallen, a Miami-based managing partner at Caracas Capital Markets.

Output Risk

A U.S. Treasury official said the department doesn’t generally comment on possible sanctions actions.

More than 200,000 barrels a day of output at four projects Chevron Corp. is keeping afloat could shut if the waivers aren’t renewed. That would be debilitating to Maduro because the U.S. company, as a minority partner, only gets about 40,000 barrels a day of that production.

The departure of the American oil service providers would hurt other projects in the Orinoco region, where operators need to constantly drill wells just to keep output from declining. The U.S.-based companies are also involved in state-controlled Petroleos de Venezuela SA’s joint ventures in other regions such as Lake Maracaibo.

Limiting Exposure

Halliburton Co., Schlumberger Ltd. and Weatherford International Ltd. have reduced staff and are limiting their exposure to the risk of non-payment in the country, according to people familiar with the situation. The three companies have written down a total of at least $1.4 billion since 2018 in charges related to operations in Venezuela, according to financial filings. Baker Hughes had also scaled back before additional sanctions were announced earlier this year, the people said.

Schlumberger, Baker Hughes, Weatherford, PDVSA and Venezuela’s oil ministry all declined to comment.

Halliburton has adjusted its Venezuela operations to customer activity, and continues operating all of its product service lines at its operational bases, including in the Orinoco Belt, it said in an emailed response to questions. It works directly with several of PDVSA’s joint ventures, and timely payments from customers are in accordance with U.S. regulations, it said.

Hamilton, Bermuda-based Nabors Industries Ltd. has three drilling rigs in Venezuela that can operate for a client until the sanctions expire in October, Chief Executive Officer Anthony Petrello said in a July 30 conference call, without naming the client.

The sanctions carry geopolitical risks for the U.S. If Maduro manages to hang on, American companies would lose a foothold in Venezuela, giving Russian competitors such as Rosneft Oil Co. a chance to fill the void. Chinese companies could also benefit. Even if the waivers get extended, the uncertainty hinders any long-term planning or investments in the nation by the exposed companies.

Rosneft’s press office didn’t respond to phone calls and emails seeking comment on operations in Venezuela.

–With assistance from David Wethe, Debjit Chakraborty and Dina Khrennikova.

To contact the reporters on this story: Peter Millard in Rio de Janeiro at pmillard1@bloomberg.net;Fabiola Zerpa in Caracas Office at fzerpa@bloomberg.net

To contact the editors responsible for this story: Tina Davis at tinadavis@bloomberg.net, Pratish Narayanan, Joe Ryan

For more articles like this, please visit us at bloomberg.com

©2019 Bloomberg L.P

Capital keeps marching out of Canada’s oil industry, with Kinder Morgan Inc.’s sale of its remaining holdings in the country on Wednesday adding to more than $30 billion of foreign-company divestitures in the past three years.

Pembina Pipeline Corp., based in Calgary, is snapping up Kinder’s Canadian assets and a cross-border pipeline in a $3.3 billion deal. For Houston-based Kinder, the deal completes an exit from a country that has frustrated more than a few companies — from ConocoPhillips and Royal Dutch Shell Plc to Marathon Oil Corp.

The drumbeat of exits, rare for such a stable oil-producing country, adds an extra layer of gloom for an industry that accounts for about a fifth of Canada’s exports. The energy sector — centered around Alberta’s oil sands — has struggled to rebound since the 2014 crash in global oil prices, with capital spending declining for five straight years and job cuts pushing the province’s unemployment rate above 6%. Alberta is forecast to post the slowest growth of any region in Canada this year.

The situation isn’t likely to improve any time soon, with key pipelines like TC Energy Corp.’s Keystone XL and Enbridge Inc.’s expansion of its Line 3 conduit bogged down by legal challenges. The lack of pipelines has weighed on Canadian heavy crude prices for years, sending them to a record low late in 2018.

“If they thought things were getting better in Canada, they might hold on, but they don’t see things getting better,” Laura Lau, who helps manage more than C$2 billion ($1.5 billion) at Brompton Corp. in Toronto, said in an interview. “The pipeline situation is getting worse; everything is getting worse.”

Read more on the Pembina deal

Other recent major divestitures include ConocoPhillips’ $13.2 billion sale of oil-sands and natural gas assets to Cenovus Energy Inc. in 2017, and Shell’s and Marathon’s sales of their stakes in an oil-sands project to Canadian Natural Resources Ltd. for about $10.7 billion that same year. Canadian Natural also bought Oklahoma City-based Devon Energy Corp.’s Canadian heavy oil assets this year for $2.79 billion. Norway’s Equinor ASA pulled out in 2016 after facing pressure at home to invest in lower-emission projects.

While a government curtailment program has boosted oil sands prices to more normal levels, the system has prevented companies from investing in new deposits. What’s more, the oil sands are often viewed by investors as a higher-cost jurisdiction that produces a lower quality of heavy crude. Those persistent drags are likely to keep Canadian assets at the top of international companies’ lists for potential disposal, Lau said.

Kinder Morgan is in many ways the perfect example of the troubles — including slow-moving regulatory processes, an active environmental movement, and a variety of inter-provincial squabbles. The company bought the Trans Mountain pipeline, which carries crude and other products from Edmonton to a shipping terminal in Vancouver, for about $5.6 billion in 2005 in a bid to gain exposure to the oil sands — the world’s third-largest crude reserves.

But a plan to roughly triple the capacity of the line got bogged down amid opposition from indigenous groups, environmentalists and British Columbia’s government. Kinder threatened to scrap the expansion, which all but forced Prime Minister Justin Trudeau’s government to step in and buy the entire line for about $3.45 billion last year. The project took an initial step forward on Thursday as contractors were given approval to start some work on the line.

Bad Signal

“When they sold Trans Mountain, there wasn’t much left, and it was just a matter of time for them to exit Canada completely,” Lau said. “But definitely another foreign company exiting Canada doesn’t send a good signal.”

Not all foreign operators have abandoned Canada. Exxon Mobil Corp. still has a sizable presence with its controlling stake in Imperial Oil Ltd., a C$25 billion company. Shell, based in The Hague, still owns a refining complex and natural gas production in Alberta and British Columbia. France’s Total SA owns a portion of the Fort Hills mine, and Japanese and Chinese companies also have oil-sands projects. Conoco still has an oil-sands facility and holdings in the Montney shale play.

A potential catalyst for the sector could be the election of a Conservative government in Canada’s federal election in October, said Rafi Tahmazian, senior portfolio manager at Canoe Financial. That may change global investors’ perceptions about the support the industry would receive from the government.

“The silver lining in this whole process is that Canada owns Canada again, and we got it pretty cheap,” Tahmazian said in an interview. “Now the question is can we take advantage of that by allowing ourselves a more friendly environment for foreign investment?”

LONDON (Reuters) – African states like Chad and Cameroon are shaping up to be big winners from new rules to cut sulfur emissions from ships, providing just the right type of oil to produce cleaner fuels.

Only around 1% of the world’s crude oil exports are heavy and sweet varieties, ideal for refining into fuel with a maximum 0.5% sulfur content mandated by International Maritime Organization (IMO) rules coming into force worldwide on Jan. 1.

The regulations will tighten limits from the 3.5% sulfur levels allowed now, aiming to improve human health by reducing air pollution.

West African oil, mostly outside the continent’s top exporter Nigeria, is set to provide the “Holy Grail” for these IMO 2020 fuels, according to market research firm ClipperData.

Nearly three-quarters of the world’s exports of heavy sweet crude – defined as oil with less than 0.5% sulfur content – come from the region, with Angolan Dalia, Chadian Doba Blend and Cameroonian Lokele alone making up most of that portion.

(Graphic: Heavy sweet crude exports link: here(2).png)

“The new environmental regulation starts in January, but preparation has already begun. Refiners need to ready their supply streams and learn how to best prepare for a low sulfur future,” said Josh Lowell, senior energy analyst at ClipperData.

“Even though trading houses and refiners are keeping their strategy and timing close to their chest, it’s clear certain West African grades really stand to benefit.”

Prices for the coveted oil are already soaring.

According to price reporting agency Argus, Doba has vaulted to 75 cents above dated Brent this month from 60 cents below at the beginning of 2018, while Dalia went from a 60 cent discount to a $2.50 premium over the same period.

By Wednesday, traders said Angolan state oil company Sonangol was offering Dalia at $3.00 above dated Brent and similar grade Girassol at $3.20.

“Outages from Iran and Venezuela after U.S. sanctions, ramped up Chinese demand and the IMO rules around the corner – all these factors have been quite supportive for medium to heavy sweet grades,” one seller of Angolan crude told Reuters.

Because much of Angola’s oil is bound to flow to China per term agreements, interest has mounted in grades trading more freely on the market.

Oil from landlocked Chad, piped south-westward and exported by sea via Cameroon, has increased in volume since new fields came online this year and is being increasingly snapped up in the world’s key refining hubs.

“Recent flows of Doba have seen it head to suppliers already providing very low-sulfur fuel oil (VLSFO) to the market,” analytics firm Vortexa said.

“Going forward, we expect continued demand from the Fujairah and Rotterdam bunkering and blending hubs, as well as from the U.S. Atlantic coast.”

Industry sources say trading giant Vitol bagged all three cargoes of Doba scheduled for export in August, with at least one bound for Fujairah in the United Arab Emirates, where refinery re-tooling is underway ahead of the rules, also known as IMO 2020.

The rule changes are requiring massive investment as refiners cut sulfur content in their output. ExxonMobil completed a $1 billion unit at its Antwerp refinery last year to upgrade high-sulfur fuel into various types of diesel, including the variant mandated by the IMO 2020 rules.

Germany’s Uniper upgraded its plant in Fujairah earlier this year to produce fuel oil with a content of 0.1% to 0.5% sulfur, while Vitol’s Fujairah refinery is already producing compliant fuels.

In a sign that the quest is afoot for comparable grades further afield, cargoes of Argentinian Escalante and Brazilian Ostra grades were also bound for Fujairah this month for the first time ever, according to Refinitiv Eikon data.

Likewise, the bunkering hub at Singapore took on more cargoes of heavy sweet Australian crude at record prices since March than in all previous years combined.

https://www.reuters.com/article/us-shipping-imo/west-african-oil-hits-sweet-spot-as-shipping-upgrades-to-cleaner-fuel-idUSKCN1VC16C

Frontline has agreed to buy 10 Suezmax oil tankers from Trafigura in a cash and share deal worth up to $675mn which will make the Geneva-based trading firm the group’s second biggest shareholder.
Under the terms of the deal Trafigura will take an 8.5% stake in Frontline valued at $128mn, and will receive a cash payment of between $538mn and $547mn, the companies said yesterday.
The agreement will allow Frontline, which is controlled by Norwegian-born billionaire John Fredriksen, to boost its future dividends, the Oslo-listed tanker operator said.
Frontline and Trafigura, together with dry bulk shipping firm Golden Ocean, announced a marine fuel partnership earlier this month ahead of a shake-up in regulation that will enforce cleaner fuels for ships.
Frontline has agreed to time-charter all the 10 vessels, which were built this year and fitted with exhaust gas cleaning systems known as scrubbers that will help them meet the upcoming marine fuels rules, until the deal closes.
“The price is reasonable, and they are (fitted) with scrubbers so… I think it’s cheap,” Frontline chief executive Robert Hvide Macleod told Reuters. “The market is about to firm considerably so I think the timing is good.”
Crude tanker freight rates have been under pressure for the best part of 2019 but are expected to improve later this year, lifted in part by the upcoming fuel regulations.
Frontline also has an option to buy a further four vessels and agreed to charter five of the vessels back to Trafigura for three years at a daily base rate of $28,400 with a 50% profit share above the base rate, the trading firm said in a statement.
At a price of about $66.5mn to $67.4mn per vessel based on Thursday’s Frontline closing price, the deal is in line with current market values, according to an Arctic Securities research note.
“We see the timing of adding high-end tankers with scrubbers at current prices as very compelling, just as the market starts to move,” the brokerage added. “(We) see today’s announcement as an attractive deal ahead of the market recovery.”
A newbuild Suezmax tanker currently costs above $60mn to order, not including costs for scrubbers, and delivery won’t take place until 2021, Macleod said.
“What is interesting about the Suezmax market is that there has been very little delivered over the last year and there is virtually nothing on the order book. So the fleet profile is looking healthy,” he added.
Frontline’s shares rose following the announcement, trading 5.3% higher at 0926 GMT.
Trafigura sees “significant upside potential in our equity investment in Frontline, a company with vast commercial scale and capabilities with whom we already enjoy a close working relationship”, its Global Head of Wet Freight Rasmus Bach Nielsen said in the statement. The cash boost will also help the trading firm reduce its debt profile as the end of its financial year on September 30 approaches.
Trafigura needs to maintain a healthy level of equity as a guarantee against debt with its bank lenders.
The firm has struggled with keeping a cap on its debt but managed to hit its targeted ratio of below 1.0 times for adjusted debt to equity during its 2018 financial year.
However, this ratio rose in the first half of 2019 to 1.16 times. Its total debt was at nearly $33bn as of March 31 this year, out of which $24bn is current debt.
Frontline’s fleet will consist of 75 vessels after the transaction, including newbuilds.
Fredriksen currently holds around 46.6% of the Oslo-listed tanker operator’s shares and will see his stake diluted to around 42% by the deal, according to a Reuters calculation.

Gazprom PJSC is considering testing the mar- ket’s appetite for its debt this year by issuing Eurobonds through a Russian or UK unit said a person familiar with the company’s plans. The Russian gas producer is working to set up a UK unit because a legal spat with JSC Naf- togaz Ukrainy makes it difficult to use its existing Luxembourg- based financial arms, the person said, asking not to be named because the plans aren’t public. Earlier this month, a court in Luxembourg confirmed the Ukrainian company’s right to demand a freeze of Gazprom’s local assets and debt. The energy giant may use the British unit by the end of the year for a small Eurobond issue, the person said. Since Decem- ber 2018, securities legislation also allows Russian corporate issuers to make direct placements of Eurobonds compliant with foreign regulations, without needing to use a special purpose vehicle, or SPV, based overseas. Gazprom does not need external financing, so any bond issue would be mainly aimed at gauging investors’ enthusiasm for the assets, the person said. Gazprom’s spokesman Sergei Kupriyanov declined to comment. Gazprom issued $1.25bn of Eurobonds in February, in what became the biggest single-tranche dollar transaction for the company since 2009. Investors initially bid more than $5.5bn amid positive sentiment for emerging- market bonds. Investors will have an appetite for Gazprom’s new debt as long as the issuer is located in a safe jurisdiction, Lutz Roeh- Meyer, chief investment officer at Berlin-based Capitulum Asset Management GmbH, said by e-mail. “Which SPV is doing it, is unimportant,” he said, adding that he views both the UK and Luxembourg as safe. Gazprom has said it has enough liquidity as it aims to complete three major gas pipeline projects this year – Nord Stream 2 to Europe, TurkStream to Turkey and Power of Siberia to China. Last week, it raised a further $2.2bn when its subsidiaries sold quasi-treasury shares equivalent to 2.9% of the company to an unidentified buyer. Gazprom’s legal battle with Ukraine is over multibillion-dollar gas transit debt payments. The Russian company has been trying to fence off Naftogaz’s attempts to arrest its assets across Europe with mixed success.

Russia’s contaminated oil crisis isn’t over yet — at least not for the traders trying to find a home for the cargoes they unwittingly bought.
BP Plc, the London-based oil giant, failed to find a purchaser for more than 700,000 barrels of Urals crude that got loaded onto a tanker almost three months ago at a port in the Baltic Sea, people with knowledge of a sales tender said, asking not to be identified because the matter is private. The cargo has excessive levels of organic chlorides that could damage a refinery if not removed.
In late April, it emerged that Russia was inadvertently sending millions of barrels laced with the contaminant through its Druzhba pipeline system to refineries across Europe, a situation that eventually caused flows to be halted. Some barrels also got sent to the port of Ust-Luga in the Baltic, where BP and other companies loaded them onto tankers.
Russia’s pipeline operator Transneft said last month that it would pay $15 a barrel in compensation to Belarus for supplies sent by pipeline. Its eastern neighbour said recompense should not be dictated.
It’s unclear what traders have been told about compensation. There was insufficient interest in the cargo for BP to be able to sell it, the people said. The shipment has an organic chloride content of about 29 parts per million. It needs to be less than 10. A spokesman for BP declined to comment.
There are still about 5mn barrels of the tainted oil on tankers in northwest Europe, Singapore and other locations, according to traders and tanker tracking data compiled by Bloomberg. That represents about 40% of the roughly 12mn barrels that were on ships at one stage during the height of the contamination crisis.

Oil tanker owners are finding a way to reduce the risks of navigating the Strait of Hormuz, the world’s most important — and lately most dangerous — energy chokepoint: vanish from global tracking systems.

Copying from Iran’s own playbook, at least 20 ships turned off their transponders while passing through the strait this month, tanker-tracking data compiled by Bloomberg show. Others appear to have slightly altered their routes once inside the Persian Gulf, sailing closer than usual to Saudi Arabia’s coast en route to ports in Kuwait or Iraq.

Before the latest increase in tensions with Iran, ships were more consistent about signaling their positions as they passed through a waterway that handles a third of seaborne petroleum. Once inside the Gulf, shipping routes took them fairly close to the Iranian coast, skirting the offshore South Pars/North gas field shared by Iran and Qatar. Most still do, but a growing number appear to be trying something new.

It’s little surprise that ships are doing everything possible to minimize risk. The Gulf region has witnessed a spate of vessel attacks, tanker seizures and drone shoot-downs since May, all against the backdrop of U.S. sanctions aimed at crippling Iran. War-risk insurance soared for tanker owners seeking to load cargoes in the region.

Two British warships are now situated in the waters around Hormuz where they were recently escorting the nation’s ships. The U.S. 5th Fleet also permanently operates in the region. On Wednesday, the Norwegian Maritime Authority advised the country’s flagged vessels to minimize transit time in Iran’s territorial waters. Tanker captains have become increasingly nervous about the risks of getting caught up in the conflict.

At least 12 vessels loaded in Saudi Arabia and shut off their transponders while passing through the strait within the past month. They include the supertanker Kahla, which turned off its signal on July 20 before passing through the strait. It reappeared two days later on the other side of the waterway.

Likewise, at least eight vessels that loaded in Iraq and Kuwait went dark while leaving the Strait of Hormuz. A vessel shipping from the U.A.E. also dropped off tracking systems.

The apparent shutdown of signals coincides with a slew of disruptions in the region. On July 11, the Royal Navy intervened to prevent Iran from impeding a tanker operated by BP Plc from passing through Hormuz. Three days later, Iran seized a Panama-flagged vessel. On July 19, Iranian forces took control of a British-flagged tanker in retaliation for similar action by U.K. authorities. The vessel, the Stena Impero, remains impounded.

Oil industry foes are preparing to go to court to fight the Environmental Protection Agency regulation issued Friday that allows year-round sales of higher-ethanol E15 gasoline nationwide.

The agency’s final rule offers ethanol producers and corn farmers the promise of greater market access and demand — but the coming legal battle will be the true test of that potential.

The regulation fulfills President Donald Trump’s promise to unleash ethanol sales and is a potent show of support to Midwestern farmers who are suffering from Chinese tariffs on soybeans, flooding that destroyed stockpiled grain and a deluge of rain that has delayed plantings. With some 37% of America’s corn production going to ethanol mills, any regulatory move lifting demand for the fuel could buttress farmers who helped propel Trump to the White House.

Iowa Republican leaders and biofuel industry boosters will celebrate the shift with EPA’s Region 7 administrator during an event at Elite Octane LLC’s dry mill ethanol plant in Atlantic, Iowa later Friday. Trump is expected to address the issue during a visit to the state next month.

“Over time, we believe and the industry believes you will see more E15 sold as the infrastructure in the gasoline distribution system and especially at gas stations catches up to the availability of this fuel,” Wehrum said. This is going to result in a “substantial increase” in E15 sales, he said.

At Trump’s direction, the EPA bundled the E15 shift with modest changes meant to boost transparency and prevent price manipulation in the trading of credits used by refiners to prove compliance with annual biofuel blending quotas. Large integrated oil companies, including ExxonMobil Corp., BP America Inc. and Chevron Corp., had argued against the EPA’s initial proposal of more aggressive trading limitations.

Wehrum said the agency would continue examining allegations of market manipulation and respond to them if needed. “We’re applying the theory of first do no harm,” he said, noting that proposed position limits and sale requirements “could reduce the flexibility of the market and the efficiency of the market.” While the agency takes the issue seriously, he said, the EPA has not yet found clear evidence of significant manipulation.

Senator Joni Ernst, a Republican from Iowa, praised the EPA’s action, saying it would mean more consumer choice and savings at the pump.

“The president had made this promise a long time ago: He was really going to work hard for farmers’ support and the Renewable Fuel Standard,” she said by phone. “And he’s coming through with that promise at a time when it’s desperately needed. It’s something we were going to work toward anyway, but it does bring much-needed relief at a very critical time for our farmers.”

Ethanol is already a staple of America’s fuel supply, accounting for about 10% of total consumption. Biofuel boosters who have lobbied for the regulatory shift are betting 15% will eventually emerge as the standard. Green Plains Inc. Chief Executive Officer Todd Becker said this month that the higher blend puts in play “year-round demand growth of at least 200 million gallons of annualized incremental demand as only the starting point.”

That would come at the expense of oil.

The American Petroleum Institute previewed its legal argument in public comments, arguing that the agency is flouting the plain text of the Clean Air Act by extending an existing waiver to E15. Marathon Petroleum Corp.warned the EPA’s move to consider E15 “substantially similar” to conventional E10 gasoline is “arbitrary and capricious” — a fatal failing under a federal law governing rulemaking. And the American Fuel and Petrochemical Manufacturers insisted the EPA is taking action previously rejected by Congress.

Ethanol advocates argue the EPA is on solid legal footing. The agency’s move to grant a waiver to E15 “reflects the best, most natural reading” of the Clean Air Act, and that higher-ethanol blend is substantially similar to E10, said Growth Energy Chief Executive Officer Emily Skor.

After staying away for four months, South Korea is back in the market for North Sea crude. Hyundai Oilbank Co bought 2mn barrels of North Sea Forties crude for August de- livery, a rare purchase this year, said trad- ers who asked not to be identifi ed because the information is private. The import was made after refi ners in the Asian nation were given incentives to look beyond the Mid- dle East for oil, and it followed a discharge of UK crude in May, the fi rst such purchase this year. South Korea imported zero oil from the United Kingdom in the fi rst four months of this year as the possibility of Brexit threat- ened to erode the appeal of the crude to one of Asia’s top refi ning hubs. Britain’s exit will mean the return of a 3% import tariff on Forties purchases that was waived by South Korea under a free-trade agreement with the European Union since 2011. While the Asian country is a steady buy- er of UK oil, purchasing an average of over 2.6mn barrels a month in 2018, refi ners were reluctant to bring cargoes earlier this year as the government delayed renewing a freight rebate scheme that encouraged purchases from regions other than the Middle East. The very-large crude carrier Farhah is scheduled to load Forties crude from Hound Point on June 20 for delivery to Daesan in August, according to traders and ship- ping fi xtures compiled by Bloomberg. Last month, supertanker Athenian Freedom also made a similar voyage, discharging a small- er cargo of the grade, ship-tracking data showed. Hyundai Oilbank operates a refi n- ery in Daesan with crude processing capac- ity of 650,000 barrels a day.