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.

LONDON (Bloomberg) – After prices plunged to their lowest on record for this time of year, traders say buyers from Japan to India have started to snap up cargoes in anticipation of a pickup in winter demand. Procurement for the colder season is only expected to intensify over what’s left of the summer.

“We have likely reached bottom,” Sanford C. Bernstein & Co analysts including Neil Beveridge said in a report.

The rout can be traced back to last winter, when mild weather dented demand for heating in large parts of the northern hemisphere. To make matters worse for producers, which are adding supply at a record pace, consumption for cooling in the past few months wasn’t very strong either. A market in contango is also pushing some traders to consider storing gas on tankers to sell later at a higher price, a practice that last year began later in autumn.

Another sign that demand is picking up can be spotted in the shipping market. The cost of hiring a tanker on a spot basis East of Suez is at the highest since January. Oystein M Kalleklev, chief executive officer of vessel owner Flex LNG Ltd., expects the LNG market to become “increasingly tight” in the second half of the year, he said Tuesday on an earnings call.

Cargoes for early September delivery to North Asia were bought between high-$3 to low-$4/MMbtu, while October shipments are currently priced around the mid-$4 level, according to traders.

In Europe, where inventories are already above last year’s high point, traders see the gap of as much as $1.50/MMbtu between September and the fourth-quarter contract as an opportunity to sell the fuel later.

One tanker, Marshal Vasilevskiy, which loaded at Rotterdam last weekend, doesn’t appear to have a destination yet and is idling off the port, ship-tracking data on Bloomberg show. Also, at least three BP Plc vessels appear to be idling for longer than usual, according to the data.

S&P Global Platts defines floating storage as any laden trip that takes 1.75 times the standard length of time to reach its destination. The company, which provides commodity price assessments and market analysis, said traders will probably float cargoes for delivery in November and December, boosting prices during autumn in the European market.

“Even if charter rates triple from current levels, marginal LNG spot supply is still profitable selling into November or December,” Platts said in a report. “We expect this dynamic to limit European regasification rates and push LNG storage to its limits in October.”

While an uptick in prices at this time of year is normal, new supply from plants in the U.S. to Australia will likely curb any bigger gains.

A record 35 million tons of LNG capacity will be added globally next year, according to Bernstein. The U.S. alone will add about 17 million tons of capacity between the fourth quarter of this year and the first quarter of 2020, said Leslie Palti-Guzman, president and co-founder of GasVista LLC, an energy consultant in New York. All the new supply, coupled with demand at the mercy of deteriorating U.S.-China trade relations, is sending a bearish signal.

“The market should question the forward winter LNG curve price,” she said.

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.

German manufacturers are reinforcing concern that Europe’s largest economy is headed into a recession.

A nationwide gauge showed orders at factories and services companies are dropping at the fastest pace in six years, and more companies now expect output to fall than rise over the next 12 months. That’s the first time that’s happened since 2014, according to the Purchasing Managers’ Index from IHS Markit.

The peek into the engine room of European industry provides a damning snapshot of the economy, which shrank in the second quarter. The persistent weakness — driven in particular by mounting global trade tensions, car industry woes and slowing demand in China — doesn’t bode well for the broader euro area.

European Central Bank policy makers have already started laying the groundwork to add monetary stimulus, and are expected to cut interest rates at their next meeting in three weeks. In Germany, the government has made only tentative steps toward a fiscal stimulus program aimed at supporting growth.

“Somehow they are not looking at this data,” said Carsten Brzeski, chief German economist at ING in Frankfurt. “The German government should react. We have this stagnation of the entire economy now and we really need some fiscal stimulus.”

While the headline German composite PMI unexpectedly rose in August to 51.4 from 50.9, the index for factories remained far under 50, signaling a seventh month of contraction. Backlogs of work across both sectors fell for a 10th month and the pace of hiring slowed, with employment in manufacturing declining at the fastest pace in seven years.

What Bloomberg’s Economists Say…

“There’s a little light at the end of the tunnel for Germany’s economy. The PMI — a trusted gauge of economic activity — picked up a little in August. The big risk is that a fresh blow to manufacturing materializes — the U.S. goes ahead with tariffs on EU car exports, for example — or that weakness in the industrial sector spreads to services.”

Composite figures for France and the euro area also beat expectations, and the euro rose. Bunds declined, though 10-year yields are still well below zero.

“Germany remains a two-speed economy, with ongoing growth of services just about compensating for the sustained weakness in manufacturing,” said IHS Markit economist Phil Smith. “Although improving slightly, the survey’s output data haven’t changed enough to dispel the threat of another slight contraction in gross domestic product in the third quarter.”

— With assistance by Matthew Miller

MELBOURNE (Reuters) – Royal Dutch Shell has made its first foray into Australia’s highly competitive power sector with a A$617 million ($419 million) takeover offer for ERM Power Ltd, the country’s no.2 energy retailer to businesses and industry.

The deal would instantly give Shell a power supplier with almost a quarter share of the commercial and industrial retail market in Australia, second only to Origin Energy in that space. It will also get two gas-fired power stations.

Shell, already one of Australia’s biggest gas producers, wants to use its global scale in oil and gas to build a power business, as the world rapidly shifts toward cleaner energy. It plans to boost annual spending on the strategy to between $2 billion and $3 billion by 2025.

“This acquisition aligns with Shell’s global ambition to expand our integrated power business and builds on Shell Energy Australia’s existing gas marketing and trading capability,” Shell Australia’s Country Chair Zoe Yujnovich said in a statement.

ERM agreed to the offer, pitched at a big 43% premium to its last closing price, and recommended shareholders should accept it in a vote expected in November.

ERM’s founder and top shareholder, Trevor St Baker, who speaks for 27% of the company’s shares, said in a statement he would accept the offer of A$2.465 a share if no higher bid emerges.

Shell, which was advised by UBS, said Australia is one of the core markets for its new ‘Emerging Power’ theme, focused on strong growth in renewables to complement traditional fuels.

The ERM acquisition fits well with Shell’s recent takeover of German solar battery maker sonnen, which has a presence in Australia, giving Shell a small foothold in selling to households alongside ERM’s big business customers.

The power business will also give Shell another product to sell to its long established big fuel customers, like miners.

ERM Chief Executive Jon Stretch said there was little overlap with Shell’s existing business in Australia, so he expected most of ERM’s staff would remain with the business.

“It’s clear that there’s little in the way of overlap and cost synergies and the focus will be on combining for growth opportunities,” he told reporters on a conference call.

ERM’s shares soared to a four and a half-year high of A$2.50 after the bid was announced and last traded at A$2.44, just below the offer price, indicating investors don’t expect a higher offer to emerge.

The company on Thursday reported underlying earnings of $90.5 million for the 2019 financial year, down 7% from a year earlier, as sales fell 8% to 17.7 terrawatt hours (TWh) of power. It forecast sales would grow to 18.5 TWh this year.

Origin Energy, which also reported its results on Thursday, said it was undaunted by the pending entry of Shell in power retailing, saying Origin has managed to grow its share of commercial and industrial customers even with ERM as a strong competitor to date.

“It continues to be a competitive market. It’s hard to anticipate what they may do differently,” Origin Chief Executive Frank Calabria told Reuters in an interview.

https://www.reuters.com/article/us-erm-power-m-a-shellenergyaustralia/shell-enters-australia-power-industry-with-419-million-bid-for-erm-power-idUSKCN1VB2L1

(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?”

(Bloomberg) — Terms of Trade is a daily newsletter that untangles a world embroiled in trade wars. Sign up here.

Liquefied natural gas may have dodged the latest round of Chinese tariffs on U.S. goods, but plans for new American terminals to ship the fuel abroad are under threat as the trade war escalates.

Tellurian Inc. and other developers will probably delay final investment decisions on multibillion-dollar U.S. LNG export projects to 2020 from this year as the tensions complicate negotiations with potential Chinese gas buyers, according to Bank of America Corp. While LNG isn’t among the goods Beijing will target in retaliatory levies that take effect next month, a 25% duty imposed in June still stands, raised from 10% previously.

The trade dispute is intensifying as roughly a dozen companies look to become part of the so-called second wave of U.S. LNG export terminals expected to start up in the next few years. Smaller developers face intense competition from deep-pocketed oil giants like Exxon Mobil Corp., Qatar Petroleum and Royal Dutch Shell Plc, which didn’t need to sign long-term contracts before greenlighting their projects. A collapse in global gas prices amid a glut of supply from the U.S. to Australia is also pressuring the industry.

For an investment decision on Tellurian’s $28 billion Driftwood project in Louisiana, “we see delays as likely given current pricing headwinds, no resolution yet on the U.S.-China trade war, and minimal contract announcements in recent months,” Bank of America analysts led by Julien Dumoulin-Smith wrote Friday in a note to clients. Joi Lecznar, a spokeswoman for Tellurian, said the company is still targeting a final investment decision this year.

Liquefied Natural Gas Ltd. will also likely push back a final investment decision on its Magnolia terminal in Louisiana to 2020 because of growing competition, and NextDecade Corp. may delay a decision on its Rio Grande project in Texas to next year, according to Cowen Inc. Toni Beck, a spokeswoman for NextDecade, said the company is still planning a final investment decision in 2019. LNG Ltd. declined to comment.

Shares of Tellurian fell as much as 19% Friday, the most since March, after surging earlier in the month. NextDecade dropped as much as 13%, while LNG Ltd. slipped 2.6%.

While China is a fast-growing market for gas, it hasn’t imported any U.S. LNG since February, according to vessel tracking data compiled by Bloomberg. The Asian nation has received 62 American cargoes since 2016, putting it behind South Korea, Mexico and Japan.

Exports of U.S. shale gas have surged since 2016, when Cheniere Energy Inc. started up the Sabine Pass terminal in Louisiana, the first to ship LNG from the lower 48 states. The nation is now the world’s third-largest supplier of the fuel, after Australia and Qatar. Though two new U.S. terminals are about to begin exporting and more are under construction, failure to resolve the trade tensions could slow the industry’s rapid growth.

“There’s increased competition from players that don’t really need third-party financing. China definitely didn’t make it easier,” Cowen analyst Jason Gabelman said in a telephone interview on Thursday.

With cargoes to China effectively halted and deliveries to Europe easing as low prices there reduce the incentive to ship U.S. gas farther afield, South America is soaking up much of the excess supply. So far this year, Argentina, Brazil, Chile and Colombia are snapping up the most U.S. LNG on record.

LNG developers may not be the only gas players hurt by the trade rift. It’s also threatening U.S. gas producers relying on exports to ease the shale glut, particularly in the Permian Basin, where prices for the fuel dipped below zero earlier this year as pipeline bottlenecks forced drillers to pay others to take their supply.

For beleaguered U.S. gas drillers, “it’s another negative,” said John Kilduff, partner at Again Capital LLC, a New York-based hedge fund.

–With assistance from Kevin Varley.

To contact the reporters on this story: Christine Buurma in New York at cbuurma1@bloomberg.net;Naureen S. Malik in New York at nmalik28@bloomberg.net

To contact the editors responsible for this story: Simon Casey at scasey4@bloomberg.net, Christine Buurma, Carlos Caminada

https://finance.yahoo.com/news/u-lng-export-plans-threatened-090000072.html

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