LONDON (Reuters) – OPEC oil output has risen in August for the first month this year as higher supply from Iraq and Nigeria outweighed restraint by top exporter Saudi Arabia and losses caused by U.S. sanctions on Iran, a Reuters survey found.

The 14-member Organization of the Petroleum Exporting Countries has pumped 29.61 million barrels per day (bpd) this month, the survey showed, up 80,000 bpd from July’s revised figure which was the lowest OPEC total since 2014.

The survey indicates Saudi Arabia is not deviating from its plan of restraining output by more than called for by an OPEC-led supply deal to support the market. Despite calls this year from U.S. President Donald Trump on OPEC to raise output, the producers renewed the supply pact in July.

OPEC’s supply curbs should eventually start to support the price of crude LCOc1, which has fallen from a 2019 high above $75 a barrel in April to $61 on Friday on concern about slowing oil demand and economic growth, analysts at Commerzbank said.

“Even the moderate demand growth that can be expected is likely – given the considerable production discipline shown by OPEC – to result in an ongoing tightening of supply and to support rising prices,” Commerzbank analyst Eugen Weinberg said.

OPEC, Russia and other non-members, known as OPEC+, agreed in December to reduce supply by 1.2 million bpd from Jan. 1 this year. OPEC’s share of the cut is 800,000 bpd, to be delivered by 11 members and exempting Iran, Libya and Venezuela.

In August, the 11 OPEC members bound by the agreement, which now runs until March 2020, achieved 136% of pledged cuts, down from 150% in July, the survey found. Two of the three exempt producers pumped less oil.

The biggest supply boost of 80,000 bpd came from Nigeria, Africa’s largest exporter, which is seeking a higher OPEC quota and in August continued to produce above its target by the largest margin.

The second-largest rise of 60,000 bpd came from Iraq, which boosted exports from both its northern and southern outlets according to the survey.

Smaller increases came from Libya, where the country’s largest oilfield, El Sharara, resumed output on or around Aug. 8 following an outage. Kuwaiti output climbed slightly while remaining below its quota, the survey found.

Saudi Arabia, which in July cut supply even further below its OPEC target in a bid to reduce inventories, has kept output at a similar rate in August. The survey pegged Saudi production at 9.63 million bpd, down from its quota of 10.311 bpd.

Fellow Gulf producer the United Arab Emirates also kept output flat and below its target.

Among countries with lower output, Iran posted the largest decline of 50,000 bpd.

The United States reimposed sanctions on Iran in November after pulling out of a 2015 nuclear accord between Tehran and six world powers. In a bid to cut Iran’s sales to zero, Washington in May ended sanctions waivers for importers of Iranian oil.

In Venezuela, supply fell slightly due to the impact of U.S. sanctions on state oil company PDVSA and a long-term decline in production, according to the survey.

July’s output was the lowest by OPEC since March 2014, excluding membership changes that have taken place since then, Reuters surveys show.

The Reuters survey aims to track supply to the market and is based on shipping data provided by external sources, Refinitiv Eikon flows data and information provided by sources at oil companies, OPEC and consulting firms.

Kuwait plans to boost production from Canadian shale deposits by two thirds and increase output of natural gas in Australia as the Opec member ramps up efforts to find and develop overseas deposits of the fuel.
The international upstream arm of state-owned Kuwait Petroleum Corp sees output of almost 20,000 barrels of oil equivalent a day at its Canadian shale gas project by year-end, up from 12,000 currently, Sheikh Nawaf Saud al-Sabah, acting chief executive officer, said in a recent interview in Kuwait City.
“It will rise to about 60,000 or so once we fully develop it, which will be in the mid-2020s,” he said. “We’re just beginning to understand its potential.”
In Australia, the company known as Kufpec won exploration rights to three new blocks in February and April. It’s producing almost 40,000 barrels of oil equivalent a day in that country and aims to raise output and produce more liquefied natural gas for export, al-Sabah said, without specifying targets. Kuwait has long planned to increase its global capacity to produce gas as well as oil. The Gulf nation currently can pump as much as 3mn barrels a day of crude from its wholly owned fields, and KPC targets a daily capacity of 4mn by next year. As a member of the Organization of Petroleum Exporting Countries, however, Kuwait has pledged to cap its oil output as the group seeks to balance the market and prop up crude.
Like many energy producers, Kuwait sees gas as crucial to future growth. Gas use is seen rising faster than demand for oil and coal as policies shift toward lower carbon emissions. The amount of new gas-production capacity investments this year could set a record, according to consultant Wood Mackenzie Ltd.
In Alberta, Canada, Kufpec plans with its joint-venture partner Chevron Corp to start developing the Waskahigan and East Kaybob areas, drilling the first of more than 370 wells over 10 years. The areas are part of the Kaybob Duvernay project producing shale gas and natural gas liquids.
“We continue to look for gas prospects in Australia,” al-Sabah said. Kufpec partnered with Woodside Petroleum Ltd at one of its blocks there, and al-Sabah’s company is exporting gas via Woodside’s Wheatstone LNG facility. Kufpec sells half its production from there under long-term agreements.
“The other half is sold with a break clause that allows us to take those molecules to Kuwait if and when we need it,” he said. “Right now the LNG market is essentially a buyers’ market, so it doesn’t make sense for us to break a long-term contract” just to sell to KPC when it can get competitive pricing elsewhere, he said.
LNG producers have feared that a massive build-out of new export projects, which began a decade ago, will outpace consumption growth and leave cargoes looking for homes. Spot prices have already tumbled since last fall and are at a steep discount to LNG sold on long-term, oil-linked contracts.
Kufpec, known formally as Kuwait Foreign Petroleum Exploration Co, may supply KPC when the global market tightens, possibly by the mid-2020s, al-Sabah said.
The company has total assets of 3.4bn dinars ($11.2bn) and is well-funded right now for its current plans.

MOMBASA, Kenya (Reuters) – Kenya exported its first crude oil on Monday, amid pointed speeches by local leaders asking the government to stick to its commitment to share revenues from future shipments equitably.

Although commercial production is years away, the discovery of oil has heightened expectations that citizens, especially those living adjacent to the deposits, will benefit.

President Uhuru Kenyatta in March signed into law a long-awaited petroleum bill that regulates oil exploration and production and outlines how revenues will be shared between the government, local communities and companies.

Of the revenues due to the state, the law allocates 20% to local government, 5% to the communities living where oil was found and 75% to the central government. An earlier draft gave 10% to the communities.

The law also says parliament will review the percentages within 10 years.

The law is required for large-scale oil production but was delayed by tussles between layers of government and residents of Turkana, the impoverished northern region where the oil deposits were found.

As the first shipment left Kenya’s port of Mombasa, three governors, an oil executive and the president compared carving up the profits to sharing a goat.

“When you slaughter a goat, the owner of the goat is left with the leg,” Turkana County deputy governor Peter Emuria Lotethiro said. “Turkana want their leg.”

Tullow Oil estimates that Kenya’s Turkana fields hold 560 million barrels of oil and expects them to produce up to 100,000 barrels per day from 2022.

London-based Tullow said it and its partners had to date invested $2 billion in Kenya.

“Having spent $2 billion, the joint venture partners will be able to get a bit of that goat. There is much more investment to come which will create jobs across Kenya,” Tullow Chief Executive Paul McDade said.

Mining and Petroleum Minister John Munyes said approval to pump water from neighboring West Pokot County to pressurize oil wells had been granted. The deal is crucial for next year’s final investment decision on proceeding to commercial production.

“By 2020 we should have the plans to let us proceed with the construction of the pipeline from Lokichar to Lamu,” he said.

Monday’s shipment was 250,000 barrels of oil. The crude was trucked to the port since there is no pipeline. The shipment’s destination was not announced.

Tullow and partner Africa Oil discovered commercial oil reserves in Turkana’s Lokichar basin in 2012. France’s Total has since taken a 25% stake in the project.

About two weeks ago, Kenya and a group led by explorer Tullow picked trading company ChemChina UK Ltd to buy its first shipments. ChemChina UK’s initial purchases are small-scale, with full commercial shipments due once the pipeline is built.

NEW YORK (Capital Markets in AfricaA) – Oil prices will rise over the next few months as global inventories shrink, before declining in 2020 as trade-war induced demand woes return to haunt the market, according to UBS AG.

The Swiss bank sees Brent crude climbing to $65 a barrel in three months, around 8% higher than current levels, it said in a note by analysts including Giovanni Staunovo. However, the global benchmark will drop to $63 in six months and $60 in 12 months, UBS said.

While seasonal supply-demand dynamics should support crude for the rest of this year, the U.S.-China trade dispute will re-emerge as the main price driver in 2020, the lender said. It cut its global gross domestic product growth forecast for next year to 3.4% from 3.6% and also lowered its estimate for oil consumption expansion to 1 million barrels a day from 1.2 million.

“If trade tensions escalate, oil demand growth could soften even more next year and pose downside risks to our new forecasts,” the analysts wrote. “The three fragile oil-export countries (Venezuela, Iran and Libya) still may influence the outcome for 2020” in either a bullish or bearish way, they said.

UBS also cut its West Texas Intermediate projections by $5 a barrel to $58 in six months and $55 in 12 months. WTI is currently trading near $56 a barrel.

On the supply side, the lender sees the Organization for Petroleum Exporting Countries and its allies likely extending the production-cut agreement that runs through the end of the first quarter. But a small increase in non-OPEC output and the drop in demand growth mean the market will be oversupplied by around 500,000 barrels a day in 2020, it said.

Source: Bloomberg Business News

LONDON (Reuters) – OPEC’s share of the global oil market has sunk to 30%, the lowest in years, as a result of supply restraint and involuntary losses in Iran and Venezuela, and there is little sign yet producers are wavering on their output-cut strategy.

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.