China oil imports, Nigeria elections and Venezuela sanctions: Commodity and energy news highlights

The Lunar New Year brings shifts in supply in demand patterns across commodities, and 2019 was no different. Chinese oil imports saw a strong year on year increase in January,  but February figures are likely to be weaker due to the vacation. Meanwhile, steel markets were braced for pent up demand as China went back to work.

Ferrous markets continued to focus on the fallout from Vale’s catastrophic iron ore dam failure, with far-reaching Brazilian legislation now responding to the disaster. Neighboring Venezuala is still in the grip of political turmoil, meanwhile, with consequences for global oil trade flows and supply chains further downstream.


Analysis: New Brazil laws seen significantly impacting Minas Gerais mines output

New state and Brazilian federal government legislation restricting the use of tailing dams may have a significant and permanent impact on iron ore production in the southeastern state of Minas Gerais, the country’s biggest producer, with both market and political implications, state government and iron ore market sources say.


Factbox and infographic: PDVSA sanctions affect flows, accelerating output declines

Click for full-size infographic


Podcast: Nigerian election puts focus on country’s energy future

The February 16 Nigerian election pits incumbent President Muhammadu Buhari against Atiku Abubakar from the People’s Democractic Party, in what is expected to be a close race. For Africa’s largest oil producer, the impact of the vote could stretch across the barrel, from crude oil exports to the domestic gasoline market.


Insight: Balance of power tilts towards renewables in Asia Pacific

Renewable energy sources are now a commercially profitable business in many parts of Asia Pacific without government largesse and subsidy support. But the renewables story has just started.


LNG supply disruptions fail to lift spot prices

Supply disruptions in the Asia Pacific region have failed to lift LNG spot prices, amid lackluster demand in northeast Asia and ample supplies elsewhere in the market. Despite production cuts at the Pluto, Wheatstone and Gorgon facilities in Australia, and Bintulu in Malaysia, there were three to five excess cargoes available for March delivery, LNG trading sources said.


Feature: Singapore bunker industry faces volatile barging cost

The bunker industry in Singapore should brace itself for volatile barging costs once the International Maritime Organization’s tighter sulfur limit rule is implemented in 2020, a development which could further squeeze barge companies that are already facing tough market conditions.


“Probably for the next couple of years we will see US LNG in Italy, because the market is in such a situation that we think there will be room,” said Eni head of gas and LNG marketing, Massimo Mantovani, addressing the EGYPS conference in Cairo.

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Brexit could lead to divergence between EU, UK sanctions against Russia

In the event of Brexit there could be long-term consequences for UK-Russia energy links, if the UK’s policy on sanctions against Russia changes to reflect its vocal opposition to the current Russian government, and close relationship with the US.

“There is a good chance the UK would eventually toughen sanctions against Russia, if and when a deal to leave the EU is finalized,” Paul Sheldon at Platts Analytics said. Currently the UK is a participant in EU sanctions against Russia introduced gradually since 2014 in response to Russia’s role in the conflict in Ukraine. These include restrictions on Russian oil and gas companies’ access to long-term financing and technology used in offshore Arctic, shale and deep-water oil production.

UK officials have indicated they will carry over all EU sanctions and can do so via the Sanctions and Anti-Money Laundering Act passed last year.

If Brexit goes ahead there may be a greater chance of the EU and UK pursuing different sanctions policies in the longer term, however. The UK has long been one of the most vocal critics of the Russian government within the EU. Last year it pushed for harsher sanctions in the wake of suspected Russian involvement in the poisoning of former intelligence officer Sergei Skripal in the UK. While other EU countries offered support by expelling some Russian diplomats, they were reluctant to introduce broader measures. Further risks lie in ongoing investigations into alleged Russian interference in the Brexit referendum, which could spark fresh calls for new sanctions.

The UK’s close relationship with the US could also fuel calls for harsher measures. “Several uncertainties persist, led by the fate of Brexit itself and the potential for tighter U.S sanctions on Russian oil at the conclusion of ongoing investigations. In the event of the latter, Brexit would make it easier for the UK to act in solidarity with the U.S.,” Sheldon said.

US lawmakers have pushed for harsher sanctions against Russia in response to allegations of Russian interference in the 2016 presidential election, and it is likely that some of these proposals will come into force. This may include restrictions on the energy sector, including development of the Nord Stream 2 gas pipeline.

This has led to a divergence in approach between the EU and the US. While they remain aligned in opposition to Russian interference in Ukraine, there is no consensus in Europe on introducing fresh sanctions on major energy projects including Nord Stream 2. The EU is looking to apply stronger regulations to Nord Stream 2, but it stands to lose out if the project is delayed or blocked, as it involves investment from several European companies and would increase gas supply capacity to Europe.

UK energy assets in Russia

Sanctions aside, analysts do not expect Brexit, if it goes ahead, to have any immediate impact on the UK’s energy interests in Russia. UK companies have continued to develop their operations in Russia in recent years, despite living with sanctions and the significant deterioration in the two countries’ political relationship.

Any changes to UK sanctions policy are unlikely to put those projects at risk, Platts Analytics believes. “We do not currently anticipate new sanctions on BP cooperation with Rosneft in conventional oil fields, or other penalties outside of the already-restricted upstream sectors of shale, Arctic, and deepwater,” Sheldon said.

The cornerstone of UK-Russian energy links is BP’s cooperation with Russia’s largest oil producer Rosneft. BP owns a 19.75% stake in the company itself, as well as stakes in joint ventures. A company spokesman said that BP’s share of output in Russia averaged around 1.1 million barrels of oil equivalent per day in 2018, around a third of the company’s overall output. This is likely to grow in future if plans to increase output from the Taas-Yuryakh and Kharampur projects go ahead.

BP closed deals to join these two projects since sanctions were introduced. It has also expanded cooperation with Rosneft outside of Russia, with Rosneft taking a 30% stake in the Zohr gas field in Egypt in 2017. In recent years BP officials have indicated that they want to continue to develop operations in Russia and with Rosneft, but will adhere strictly to sanctions.

British-Dutch company Shell also continues to operate in Russia, through its joint projects with Gazprom. It holds a 27.5% stake in the Sakalin 2 oil, gas and LNG project, and a 50% stake in Salym Petroleum, which produces around 120,000 b/d of oil. Shell is also one of the investors in the Nord Stream 2 pipeline project.

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Insight: Aluminum costs push Japan’s brewers to put new beer in new bottles

From relatively traditional roots, the Japanese beer industry became a hotbed of innovation in 2018.

For over 100 years, legislation dictated that beer had to contain 67% malt, with the balance of 33% strictly water, hops, yeast, corn, rice, or more malt. But a revision of the country’s alcohol laws – or “Shuzei ho” – which went into effect April 2018, allowed breweries to introduce a new gamut of flavors, including potato, fruit and spices. The revised legislation has also allowed the malt content in beer to be lowered to 50% from the earlier 67%.

The legislation opened ways to reduce input costs and create more innovative product lines offering new and different drinking experiences. With brewers facing a challenging domestic market due to Japan’s declining population, they quickly embraced the opportunity. Products with fewer calories, less sugar and purine soon sprouted, as well as beer-tasting beverages with no alcohol, appealing to the health-conscious.

One liquor store owner said they were satisfied with the resulting sales. Instead of detracting from real beer sales, he said non-alcoholic “virtual beer” was contributing to sales of its more potent counterpart.

“After giving their liver a break with virtual beer, customers go back to drinking real beer the next day,” he said.

Virtual beer appears to be creating a new market, allowing customers to relax outside without going to a bar. Many offices do not allow non-alcoholic beer to be drunk at work, so instead people often take their drinks outdoors to unwind.

It’s not the first time that Japan’s breweries, steeped in hundreds of years of tradition, have decided to experiment: 2015 saw the launch of collagen beer, a brew with added collagen, targeting women who want to increase their intake of the natural protein.

Losing its fizz?

The rise of virtual beer has implications not just for the future of the beverage industry, but also for the aluminum that has traditionally been used to make beer cans.

The beverage sector in Japan uses 20–30 billion cans annually, driving total aluminum consumption of 400,000–500,000 mt/year. This consumption is drawn from primary aluminum, all of which is imported, as well as recycled cans sourced locally.

The cans are made domestically by melting the primary aluminum and used can feedstock, pressing the molten aluminum into sheets, and cutting the sheets into cans. Japanese can imports are marginal, at 50 million cans per year – or about a quarter of a percent at most.


Beer input costs, 2016 vs. 2018


The prices of key inputs for Japan’s breweries changed significantly between 2016 and 2018. For example, between January 2016 and January 2018, the price of imported hops fell 64% to just ¥1,297/kg ($11.77/kg), according to customs data.

Price movements in other materials, such as ethanol, wheat and aluminum, were less favorable (see chart, below). Although the aluminum used in cans typically only makes up 5–10% of total production costs, the “all-in” price of Japanese aluminum, including both the LME cash aluminum price and the S&P Global Platts CIF Japan spot premium, rose 22.8% between January 4, 2016 and January 4, 2018, reaching $1,941.25/mt. By January 28, the all-in price had risen further to $1,942.75/mt.


Japan aluminum prices


The shift in Japanese aluminum prices reflects a drastic change in fundamentals. In 2015, aluminum supply was so abundant that, at times, using fresh aluminum was cheaper than recycling used beverage cans. Since then, the global aluminum balance shifted towards a deficit thanks to increases in demand from emerging market economies, as well as the closure of high-cost smelters in China and elsewhere.

Since 2016, China’s war against pollution has led non-compliant steel and non-ferrous metal production facilities to close, while the country’s government has been discreet about new plant starts.

Then there was the US government’s targeting of Russian aluminum producer Rusal with sanctions in April 2018 – a decision that was only reversed on January 28 this year. Within two weeks of the sanctions being imposed, benchmark LME aluminum prices rose by $599/mt, or about 30%.

Rusal had previously been exporting 4 million mt/year to Japan, leading to concerns this supply could suddenly become unavailable. In the two weeks after the sanctions were announced, the S&P Global Platts CIF Japan spot premium ballooned from $112.50/mt to $187.50/mt.

Other, longer term factors have also been at play – including rising consumption from domestic auto manufacturers. The beverage industry’s 400,000-500,000 mt/year aluminum consumption is larger than that of the automotive sector, which stands at about 300,000 mt/year. However, market participants forecast auto demand will outgrow that of the beverage sector. Kobe Steel forecasts Japanese aluminum sheet demand for cars will soar seven-fold from 2016 to 2025. Japan’s total aluminum sheet production capacity is 2 million mt/year, which would not be enough to accommodate demand growth from the auto industry.

If brewers intend to continue using 400,000-500,000 mt/year of sheet metal for cans, they need to pay to sheet makers attractive processing fees to match that of automakers. Currently, automakers are said to be paying at least 30% more for their sheets.

Thinner sheets
Challenged by higher aluminum prices, brewers have tried aluminum cans made of thinner sheets. In 2016, Kirin and Universal Can co-developed an aluminum can weighing just 13.8 grams, the lightest can on record in Japan. The Kirin-Universal can achieved a weight reduction of 0.8 grams, or 5%. If used more widely, the can would result in savings of roughly $100 for every 70,000 cans.


Packaging material price trends


To go even further, breweries have looked at less costly substitutes. But cost is not the only ingredient for success when it comes to beer packaging: the material needs to provide strong protection from heat and light, ease of transport, and should also be recyclable. Steel and glass are two potential alternatives. However, while steel can be less than quarter of the cost of aluminum, it is heavy by comparison, as are traditional glass bottles.


Packaging material properties


Of these criteria, recyclability has become increasingly important as environmental sustainability is now a key operating metric for beverage makers. Breweries are vocal about being green, and some plants aim for the full reuse and recycling of all resources. Japanese beer makers resell waste from breweries to livestock farms, while containers are recycled. Aluminum can be used for several life cycles, with cans being re-melted and used over and over again.

On a relative basis, PET is increasingly seen as an ecologically friendly resource. As of 2017, Japanese recycled plastics production stood at 2.06 million mt/year, according to the Japan Waste Management Institute. Of the total 2.06 million mt, around 26% of this is PET, while 20% is polypropylene, 16% polyethylene and 15% PVC.

In response, breweries made what some might consider a logical cost-control decision: to move towards plastic bottles made from PET. However, the move was confined to non-alcoholic virtual beer. Although there is no official explanation as to why, sources said was likely the non-traditional market segment was less hostile to change than drinkers of real beer, who had got used to sipping their beverages from aluminum cans during the past 30 years.

Non-alcoholic brews that now come in unusual PET bottles include Suntory’s All Free All Time and Asahi Brewery’s Asahi Dry Zero Spark. Both look like radically different products compared with the traditional beers to which Japanese drinkers have become accustomed.

Outside the beer industry, PET and paper dominate the market for food packaging. If PET were to entirely replace aluminum in the beverage sector, as much as 500,000 mt/year of Japanese demand could be under threat. But sources suggest such a move is unlikely. One can maker said aluminum will continue to comprise a major share of beer packaging.

The liquor store owner agreed. The overwhelming majority of buyers still reach out for aluminum cans, he said, rather than PET.

“The feel of aluminum cans and the taste of beer come together.”

Additional reporting by Andrei Agapi, Hui Heng, Srijan Kanoi, Samar Niazi, Vanessa Ronsisvalle, Serena Seng & Takmila Shahid

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In the LOOP: Narrowing Dubai/LOOP spread dampens US sour crude exports

Narrower price spreads between US crudes and Dubai-based crudes have limited arbitrage opportunities to export US crude to Asia recently, S&P Global Platts data shows. However, some deals continue to get done as US crude delivered to Asia remains at a slight discount to competing grades.

In the first 29 trading days of 2019, the spread between LOOP Sour and Dubai has averaged about $2.60/b. That is compared with an average spread of $2.75/b during the same period a year ago.

As Dubai’s premium over LOOP decreases, US-based sour crudes become less competitive with comparable Dubai-based grades in export markets. The Dubai/LOOP Sour spread reached its widest point of the year so far on January 11 at $5.11/b. Its narrowest point of the year came January 25 at 90 cents/b.

The LOOP Sour-Dubai spread has been mostly narrowing since the fall as US Gulf Coast sour crude differentials have soared in recent weeks. US crudes, particularly sour grades, have jumped on concerns over the supply of medium and heavy sour crudes due to OPEC production cuts and uncertainty arising from US sanctions on Venezuela.

The 10-day moving average between LOOP Sour and Dubai was $2.40/b on Monday compared with $3.60/b one month ago and $4.40/b two months ago. One US-based crude buyer for an Indian refinery said that US crude differentials are too expensive at the moment to make export deals work.

“Prices are too high,” the crude trader said. “The arb is closed.” While the window of opportunity to move US crude is limited, some deals continue to get done, likely because values for delivered US crude to Asia remain at a discount to competing grades.

On Monday, S&P Global Platts assessed LOOP Sour CFR North Asia at $62.13/b. It is still at a small discount to comparable values for competing grades as Dubai was assessed at $63.10/b, and Basrah Light at $62.80/b.

Buyers in Asia may be looking to alternatives to expensive VLCCs in order to move crude from the US. ATMI on Friday was heard to have fixed the Suezmax Sonangol for a US Gulf Coast to West Coast India voyage in February. Oxy also arranged for a VLCC to carry US crude to China in March. No US-to-East fixtures were heard done Monday.

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King coal retreats in Europe, but still powers global growth

Coal is having a bad time in Europe. Germany – the world’s fourth largest economy – has announced it will phase out coal-fired power generation by 2038 while in the UK, the closure of another large coal plant was announced.

Despite these setbacks, the fuel of the industrial revolution still has a vital role to play powering global growth in the future.

German power plant operators have until next year to outline plans to replace lignite – often referred to as “brown coal” – as an electricity generating fuel. Last year, coal and lignite-fired power stations met 35% of German electricity demand, equivalent to generating over 200 TWh of power.

The question is whether Germany – Europe’s biggest manufacturing nation – can remain competitive without cheap coal to generate power, especially in its strategic steel sector. According to the country’s steel federation, WV Stahl, annual additional energy costs would be €250 million for the entire sector. The total cost to the economy would be much greater.

Costs for industry from higher power prices are controversial, with industry association BDI estimating a €14 billion hike at least. Germany’s big exporters are already exempt from green levies and may push hard for further exemptions, especially from rising carbon taxes. Despite these costs German industry is largely unconcerned.

Nevertheless, the phase-out recommended by Germany’s coal commission in late January effectively brings to an end over 900 years of industrial history. At their peak, pits spread across the Ruhr and Saarland helped turn the German economy become the manufacturing powerhouse it remains today. In their place will come a reliance on imported gas and renewables.

Resistance from the regions?

Politics could still extend coal’s lifespan in Germany. Some of the country’s largest opencast lignite mines are located on Germany’s eastern border with Poland where the nationalist Alternative for Germany (AfD) party has built its support base amongst the region’s working class. The AfD may seek to slow down coal’s phase-out and defend jobs if they are successful in forthcoming elections in Saxony and Brandenburg.

However, on the left bank of the Rhine a 1,000-year old forest stands in the way of a giant lignite mine and has become a high-profile environmental battle ground. For political groups in this area, the shutdown of coal can’t come quick enough. Even after Chancellor Angela Merkel steps down in 2021 they will push hard for a rapid implementation of the coal commission’s plans.

Britain – unlike Germany – depends entirely on imports to fuel its last six coal-fired electricity generation plants. Since 2007, when Prime Minister Tony Blair signed the UK up to some of Europe’s most ambitious targets for renewable energy, coal has been in rapid decline as a generating fuel. EDF Energy’s decision this week to close the 2 GW Cottam power station in the Midlands is expected soon to be followed by the shuttering of SSE’s Fiddler’s Ferry plant in Cheshire.

Rising costs for consumers are a likely by-product of King Coal’s slow death in Britain, with low-carbon replacement capacity more expensive. UK energy bills are already among the highest in Northwest Europe and token tariff caps won’t protect non-switchers from global commodity markets, as regulator Ofgem has just demonstrated with a £100-per-year hike to the cap.

“We assume that Cottam and Fiddler’s Ferry both close at the end of the summer, while also assuming neither are commercially operational for the summer itself, meaning they are focused only on meeting their capacity market commitments,” said Glenn Rickson of S&P Global Platts Analytics.

Fueling Asian industry

However, the demise of coal in the birthplace of the industrial revolution is meaningless compared to the crucial role it plays in powering Asia’s rapid economic growth, especially in China and India. Coal generates about 70% of the electricity produced in both countries. The International Energy Agency expects global coal demand to continue rising through to 2023 with Asia offsetting declines in Europe.

“The global economy needs coal,” said Alexey Danilov, director of Carbo One, a Cyprus-based coal trader with operations around the world, in an interview with S&P Global Platts this week. “Coal played a vital role in the Industrial Revolution and even today it accounts for about 40% of the global energy mix. It is used in steel production and other industries like pharmaceutical industries, paper manufacturers etc. People just need to know more about it.”

Go deeper: S&P Global Platts interviews  Carbo One director Alexey Danilov

For China, cheap coal-based electricity is essential to maintaining its low-cost industrial advantage. Although China added 40 GW of solar PV last year, the country commissioned about 38 GW of new coal-fired capacity, S&P Global Platts Analytics data show. A further 57 GW are currently under construction, further underscoring the fuel’s importance to the world’s second largest economy.

Although renewables, natural gas and LNG will eat into coal’s entrenched position in Asian electricity generation the fuel continues to be the lowest-cost option for power markets in the world’s fastest growing economies.

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Palladium extends bullish streak as automakers cool on diesel

“If there’s one trade that keeps me up at night, it’s palladium. If you want my advice, stay clear of it,” were the comforting words of one senior trader who spoke to S&P Global Platts recently.

Palladium has been sky-rocking over the past two years, creating not only a sense of jubilation for those on the right side of the trade, but also fear for those trying to gauge the metal’s next move. As ever with trading, it’s all in the timing.

From a spot bid price of $700/oz at the start of 2017, the metal hit an all-time high of $1,440/oz in early January but then took a hammering lower. It leveled out around $1,320/oz, taking a breather that tempted some to question if the hot streak was finally over. Clearly not, because palladium was at a spot bid price of around $1,385/oz February 11.

“One of the major reasons for palladium’s price surge became clearer in Nornickel’s Q4 production results, where quarter on quarter palladium output fell 10% to 632,000 oz, leaving the full year down 2% at 2,729,000 oz,” noted financial services company BMO in its research. Nornickel is the world’s largest producer of palladium.

In November 2018 the company’s head of sales, Markus Meurer, told Platts that spikes in the price of palladium continue to be a cause for concern.

“We would like to grow the palladium business steadily, rather than seeing rapid price moves,” he said. “A healthy palladium price is good, but we don’t like it spiking.”

In short supply, palladium was given a boost last year by the move away from diesel cars. The metal is primarily used in petrol vehicle autocatalysts to reduce emissions.

The consensus estimate in the market is that around 85% of palladium demand goes into gasoline engine autocats.

The “diesel-gate” emissions scandal that unfolded in 2015 was a major contributor to the “perfect storm” for palladium according to Meurer. He factored in growing demand not only from the physical market but also speculators, alongside stricter emissions regulations and implementation.

After the recent price correction, not the first and likely not the last, Mitsubishi analyst Jon Butler cautioned the market may be getting too frothy.

“With signs of rising [palladium] sponge inventories and waning industrial demand, we question the sustainability of the two-year uptrend,” Butler said in a research note, adding that the new high appeared to have been almost entirely driven by speculation.

“Palladium appears to be a two-tier market at present — investment demand in the OTC market has been very strong, whereas industrial demand has been weakening — there is evidence of this in the elevated premium of ingot (the investment form of the metal) over sponge (the industrial form),” Butler said.

Mitsubishi is forecasting an average palladium price of $1,150/oz in 2019, in a range of $1,050-$1,350/oz.

The London Bullion Market Association’s 2019 price forecasts, representing 30 analysts’ views and estimates, put forward a resoundingly bearish outlook. Participants from banks, brokerages and other outlets predicted it would be the worst performing precious metal in 2019. However, they wrongly made that prediction about palladium for 2018, as it continued on its longest bull run in history.

In the latest forecast, the sector predicted a 2019 average price of $1,267.68/oz, a high of $1,715/oz and a low of $900/oz — giving a huge $815 trading range, nearly two thirds of the average price.

A second senior trader at a major refiner told Platts a hefty correction was inevitable after a record-breaking rally.

“It’s bound to attract profit taking. Ingot supply is still tight. People are so quick to accept extreme conditions as the norm. Yes, lease rates have come down from 35%, but they are still [circa] 16%. It’s not like it has come back to flat. Forward rates are still in a backwardation,” the trader said.

Lease rates are the cost of borrowing a metal – a strategy used by companies including auto manufacturers, to avoid having too much raw material sitting on inventory. Lease rates tend to rise when physical supply is tight and fall when it improves.

“We may well never get back to $1,440 but the price is still $500 plus higher than 12 months ago,” the trader added.

For now, it seems the ball is firmly in the bull’s court, but the market is braced for volatility.

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Insight: Balance of power tilts towards renewables in Asia Pacific

Renewable energy sources are now a commercially profitable business in many parts of Asia Pacific without government largesse and subsidy support. But the renewables story has just started.

Primary energy demand in the region is expected to grow by over 40% to 2040, based on the International Energy Agency’s central scenario, accounting for two-thirds of global growth.

Renewables will play a major role in meeting the new demand, their expansion supported by rapidly falling costs of key technologies, the drive to reduce air pollution, particularly in China, and the rising popularity of electric vehicles that is pushing forward battery technology.

A tipping point now looks close on multiple fronts. Here are six trends that will have a decisive impact on the renewables landscape in the Asia Pacific region.

China’s last new coal plant in sight

There’s a joke that the Chinese government’s facial recognition technology is so advanced because it has to operate in hostile conditions like the thick smog that regularly envelops Beijing city.

Chinese cities have been some of the most polluted in the world on the back of rapid industrialization and coal consumption. The government tried to remedy this with its “war against pollution” that initially covered 28 major cities including Beijing and Tianjin.

Go deeper – The Chinese dream: Energy and commodities in an era of change

In July 2018, it expanded the initiative to other pollution hotspots like the provinces of Shanxi, Shaanxi and Henan and the industrial hubs of the Yangtze River Delta.

China’s blue sky policy, the enforcement of coal-to-gas switching, and the structural shift in China’s economy to a consumer base from an industrial base will ensure its last coal-fired plant is built sometime in the next decade.

While China’s overall energy demand will continue to rise, an increasing proportion of the growth will come from natural gas, renewables and nuclear, especially as coal demand growth plateaus.

China thermal power output

Several indicators show China’s coal demand growth hitting a wall.

China’s coal demand grew by 8.9% per year on average over 2000-2013 and contributed more than three-quarters of total energy demand growth over that period. By 2017 it constituted around two-thirds of China’s energy demand, according to the IEA.

In its 2018 report, the IEA said investment in new Chinese coal-fired power plants in 2017 fell to its lowest level in a decade, and while capacity additions were still larger than retirements, they had slowed dramatically.

“The boom years for coal-fired power investment, driven by an extraordinary expansion of capacity in China in the 2000s, are over,” the IEA said.

It said that once plants currently under construction enter into service, the rate of capacity additions will slow sharply along with a marked shift in the technologies being deployed in favour of more efficiency and lower emissions.

“China had been adding about 47 GW of coal [plants] per year over the past decade, but the pace of the coal additions has been steadily declining from a high of 51 GW in 2015 to only about 40 GW in 2017,” according to S&P Global Platts Analytics’ December report.

Beijing has restricted many provinces from adding new thermal capacity to the grid, but the provinces have been finding loopholes to proceed with the projects. Regardless of a further crackdown by the government, overcapacity will force the pace of new coal plant construction in China, the world’s largest coal user and producer, to decelerate further.

“Our view is that coal-fired generation will peak in the early to mid-2020s, although that peak could come earlier if renewables growth continues to surprise and the nuclear newbuild continues to be successful,” Platts Analytics said.

Indian solar becomes cheaper than coal

India has become one of the largest solar markets in the world.

This is primarily due to one important milestone – it is now cheaper to build 1 MW of a renewable energy project than an equivalent amount of coal-fired power, without subsidy support. The next key marker will be when the cost of renewable energy becomes cheaper than operating an existing coal plant.

India has the cheapest new wind and solar anywhere in the world, according to Bloomberg New Energy Finance, which says that while coal-fired electricity will continue to grow in the short to medium term, by 2050 wind and solar will dominate, supported by batteries and gas for flexibility.

New Delhi has laid out a renewables target of 175 GW by 2022, of which 100 GW will be solar and 60 GW wind energy; and a 2027 target of 275 GW renewables of which 150 GW will be solar and 100 GW wind.

India solar power capacity growth

It proposes to generate 46.5% of its electricity demand from non-fossil fuels by March 2022, including nuclear, hydro and other renewable sources, and increase this to 56.5% by March 2027. Currently, these sources account for 36.16% of electricity demand.

“The 2022 wind target is fairly realistic, with its 2027 target potentially harder to achieve absent additional policy measures to compensate for lower resource potential,” Platts Analytics said, adding that Indian solar installations will continue to grow through 2040, driven in part by ongoing competitive state auctions, although the magnitude of its targets as well as fiscal constraints will be challenging.

In October 2018, India announced that it had the fifth-highest solar installed capacity in the world of 24.33 GW, and the fourth-highest wind installed capacity in the world of 34.98 GW.

EVs will redefine mass power storage

Both in Asia and elsewhere, the biggest challenge in the growth of renewables is intermittency. 1 MW of solar or wind does not have the same round-the-clock stability as 1 MW of coal.

One way of filling the gap is battery storage, which is expensive and not commercially feasible for more than one or two hours today. The next renewable energy growth cycle is contingent on the development of low-cost battery technologies.

However, battery demand in the power sector is dwarfed by the automobile sector. And the economies of scale for EV battery production are much greater than in the utilities sector.

“Battery costs’ reductions are driven by increases in manufacturing scales driven by electric vehicle (EVs) growth expectations and improvements in chemistries that increase the energy density and reduce material needs,” according to Platts Analytics.

China leads in passenger EV sales

When EV production scales up it will drive down battery costs and increase the penetration of renewables in the energy mix, similar to how mass commercialization of lithium-ion batteries in electronics like smartphones made it possible for carmakers to produce the first wave of EVs.

Projections of demand for core battery metals give an idea of the scale of battery demand from EVs versus power grids. Glencore estimates nickel demand from non-petroleum vehicles at nearly sevenfold of grid storage by 2030 and cobalt demand will be nearly five times more.

Battery technologies are far from being fully standardized and are still evolving. Platts Analytics expects lithium batteries to remain the primary technology in the near to medium term, although the degree of convergence between EV and power markets will depend on supply and demand dynamics.

Battery manufacturing capacity was below 50 GWh per year in 2016, but annual capacity could reach more than 300 GWh within the next five years, with two-thirds of new capacity coming from plants in China, Platts Analytics said.

Solar power thrives in Thailand

Thailand is unique among developing Asian countries for consciously minimizing coal use in its power generation mix, due to a history of environmental and human casualties at coal-fired mines and power projects.

It generates nearly 67% of its power supply from natural gas, 22% from coal and lignite, and the remaining 11% from renewables like solar, hydro and biomass, according to official data.

In terms of absolute capacity, Thailand not only has the most solar power generation capacity in Southeast Asia, it has added more solar capacity in the last five years than the rest of Southeast Asia combined.

Thailand leads SE Asia solar capacity

In 2017, Thailand had 2,702 MW of solar generation, up from 49 MW in 2010, and compared with 1,515 MW in the rest of Southeast Asia combined. The Philippines came in at second place with 885 MW of solar, according to the International Renewable Energy Agency.

“Other regions can quickly catch up. We expect the solar capacity in Thailand to increase over threefold in the next 10 years and escalate further once the storage technology becomes commercial,” said Dr Bikal Pokharel, research director at Wood Mackenzie.

“We expect the share of gas in the mix to stay close to 50% by 2036,” he said, adding that dependence on LNG imports will increase as domestic and piped gas imports decline, and LNG will form more than 50% of the gas demand by 2036.

Australia’s turbulent transition to renewables

Australia is the world’s largest coal exporter and coal ranks as the second-largest export commodity for Australia in terms of revenue, according to the US Energy Information Administration.

Yet the country is unlikely to build another coal-fired power plant, despite 63% of its power supply coming from the fossil fuel. Australia is a case study on how to, and sometimes how not to, make the transition from fossil fuels to renewables, as it struggles with the planned phase-out of old coal plants and the associated risks to energy security.

Coal-fired power output in decline

A massive power outage in South Australia in 2016 exposed the dangers of phasing out coal without contingency plans, to the extent that Tesla founder, Elon Musk, took up the challenge of building one of the world’s largest batteries in the state in record time.

The lack of a comprehensive national-level energy policy has not helped matters.

“The uncertain landscape continues to undermine investor confidence to plan and undertake investment in new generation capacity to meet variable market conditions,” according to a report by S&P Global Platts Ratings published last September.

It said Australia’s energy policy uncertainty is delaying vital investments in system reliability amid a number of large-scale coal plant retirements in the coming decades.

However, its investments in renewables are still being driven by lower technology costs of wind turbines and solar panels compared with conventional coal or gas-fired generation. Individual state-based targets and renewable schemes, and international investors attracted to the Australian market are also factors supporting renewables growth.

China’s curbs on solar have global impact

China accounts for more than half of global solar demand and manufacturing.

But in May 2018, the Chinese government halted government support for its solar sector including the removal of subsidies, which had resulted in a growing deficit of several billion dollars at its Renewable Energy Development Fund.

The National Energy Administration also wanted to cool down the sector, as rapid growth has led to overcapacity concerns, and focus on improving the connectivity of solar plants to the power grid rather than adding more unused capacity.

The new policy went further to state that no construction quota would be allocated for utility-scale plants, and a quota for distributed generation was set at 10 GW, among other curbs.

China ranks highest for installed solar capacity

This has massive implications for solar markets globally.

“The first impact of the policy is that we lowered our China PV demand forecast for 2018-20,” said Yvonne Yujing Liu, solar power analyst at BNEF, adding that it also resulted in a more significant equipment price drop that depressed global prices.

BNEF estimated that the utility-scale PV market in China contracted by more than a third in 2018 because of policy revisions. Liu said solar equipment manufacturers were under great price pressure, and developers and investors had been forced to cancel and postpone entire project pipelines.

“On the other hand, overseas PV developers can now enjoy cheaper equipment from China,” she added.

Researchers at Wood Mackenzie said China’s curbs created a global wave of cheap equipment that reduced the benchmark global PV cost to $60/MWh in the second half of 2018, a 13% drop from the first half of 2018.

With costs for solar equipment plunging globally, there is now a big incentive to build more solar projects outside China.

The post Insight: Balance of power tilts towards renewables in Asia Pacific appeared first on The Barrel Blog.


No relief at pump when US becomes net oil exporter in 2020

The US will become a net oil exporter sometime next year. That is, total exports of both crude oil and refined petroleum products will exceed total imports.

It’s a remarkable milestone, even if it doesn’t mean that the US is self-sufficient in oil production or insulated from the global market. It reflects the staggering growth in US production in recent years. At the same time, it exposes the importance of crude quality – because the US produces type of oil that most of its refiners were not configured to process.

President Donald Trump praised the milestone in his State of the Union speech to Congress Tuesday, albeit before it actually happens. “The United States is now the number one producer of oil and natural gas anywhere in the world. And now, for the first time in 65 years, we are a net exporter of energy,” Trump said.

The Energy Information Administration expects the US to flip from longtime net oil importer to net oil exporter in the third or fourth quarter of 2020. A decade ago, EIA forecast in its 2009 Annual Energy Outlook that foreign crude would meet 44% of US demand in 2020. Imports met 60% of US consumption in 2006 and were projected to fall to 50% by 2010, according to the 2009 report. That was before the US tight oil revolution got underway in earnest.

The 2019 AEO report released in January predicts foreign oil will meet just 7.5% of US demand this year. EIA’s projections have accelerated as US oil production growth keeps beating expectations. Even just two years ago, EIA’s 2017 AEO forecast the US remaining a net importer through 2050, with foreign oil meeting 17.7% of national consumption that year. Last year’s AEO predicted the US would gain net exporter status in 2029 – nine years later than the current forecast.

Top producer

The US became the world’s top oil producer last year. It pumped 11.9 million b/d of crude in November, the latest data available, and may have already crossed the 12 million b/d mark. EIA sees US output hitting the next threshold of 13 million b/d in October 2020. “We expect the United States to remain the world’s largest producer,” EIA Administrator Linda Capuano said in January.

Anyone who follows US energy policy knows that the US’ top producer status doesn’t keep global market forces out of American drivers’ pocketbooks. Look at US oil policy just in the last year and see the many times the White House leaned on foreign oil producers to increase their own supply in order to keep American gasoline pump prices low.

Leaning on OPEC

President Donald Trump practically invited himself to last year’s OPEC meetings by tweeting his wishes for more production and lower prices. When the US moved to reimpose sanctions on Iran, the White House kept a close watch on global crude prices and again leaned on OPEC producers like Saudi Arabia to pump more. Brent prices rose sharply in October on expectations of strict enforcement of the sanctions, until the White House granted a raft of waivers to Iran’s top oil customers including China, India, Japan and South Korea.

More recently, US pump prices were a consideration in the White House’s rollout of sanctions against Venezuela’s state-owned oil company PDVSA.

“There’s been a big reduction in the overall price of oil and particularly since we instituted the Iran sanctions,” Treasury Secretary Steven Mnuchin said January 28 during a White House briefing announcing the Venezuela oil sanctions. “I think you know we’ve been very careful in making sure that these costs don’t impact the American consumer,” he added.

“Gas prices are almost as low as they’ve been in a very long period of time. These refineries impact a specific part of the country. And I think, as you’ve said, we’re very comfortable that they have enough supply that we don’t expect any big impact in the short term.”

Crude quality matters

However, the interconnectedness of the global oil market often gets lost when Washington policy makers talk about US oil abundance. “One of the things I’ve heard from the Americans is, ‘We’re producing all this crude, we don’t need any Canadian crude,’” said Jonathan Stringham, manager of fiscal and economic policy at the Canadian Association of Petroleum Producers.

The US imported 4.2 million b/d of Canadian crude in November, according to the latest EIA data. Some Gulf Coast refiners are hoping to use heavy crude barrels from Alberta to replace Venezuelan imports blocked by the recent US sanctions, although pipeline and rail constraints will keep Canada from meeting any more than about 100,000 b/d of additional heavy crude demand this year, according to S&P Global Platts Analytics.

“What we’re trying to communicate to the average American is that Canadian crudes don’t compete with American crudes,” Stringham said. “With the different quality adjustments and types of crude – heavy, light — there’s still a need for heavy crudes in the Gulf.”

The US snagged the net oil exporter title for all of one week last November, driven by a surge of 3.2 million b/d in crude exports that pushed crude and product exports above 9 million b/d, according to Platts Analytics. Whether and when the US becomes a net exporter on a monthly and annual basis of course depends on oil prices.

EIA’s reference case projects US net oil imports of 1.58 million b/d in 2019 before flipping to net exports of 460,000 b/d in 2020. Net exports would max out at 3.68 million b/d in 2034 before starting to decline. EIA’s low price scenario shows the US never reaching net oil exporter status through 2050. A high price scenario, however, shows US net imports of 50,000 b/d this year before switching to US net exports of 2.51 million b/d in 2020 that keep rising until 8.39 million b/d in 2033.

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In the LOOP: Crude delivered in January nearly triples, driven by sour demand

Strong demand for sour crude grades helped boost LOOP Sour deliveries in January.

In a recent report from the Louisiana Offshore Oil Port, the company said LOOP Sour demand nearly tripled month on month, increasing by some 620,000 barrels to more than 985,000 barrels, which is about 32,000 b/d. It was the largest volume of LOOP Sour crude pulled from the Louisiana storage cavern since September.

A shortage of sour crudes along the US Gulf Coast has inverted the typical sweet-sour relationship globally. Additionally, US sanctions on Venezuela could further increase demand for sour grades.

LOOP Sour comprises US Gulf of Mexico grades Mars and Poseidon and a crude blend called Segregation 17, named after a cavern into which the Middle Eastern grades Arab Medium, Basrah Light and Kuwait Export Crude can be delivered. The grade has been most similar to Mars in terms of API gravity over the past 12 months, averaging 0.33 degree off Mars’ typical 29.44; and from a sulfur standpoint, averaging 0.02 percentage point off Arab Medium’s typical 2.53%.

LOOP Sour delivered ex-cavern in January was slightly heavier and sweeter than the month before, averaging 29.9 API and 2.23% sulfur.

Separately, the Louisiana Offshore Oil Port will auction 7,200 capacity allocation contracts in its monthly crude storage auction on Tuesday, which collectively equal 7.2 million barrels of storage for the medium crude blend LOOP Sour. The minimum bid price LOOP will accept during the auction is 5 cents/b. Monthly storage for LOOP Sour traded around 5 cents/b for all of 2018.

Auction cohost Matrix Markets said LOOP will sell up to 3,600 storage futures contracts and 3,600 physical forward agreements. The front-month contract of March will see 400 CACs put up for sale.

Last month LOOP and Matrix sold a total of 6,690 CACs of the 7,350 that were offered.

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