As IMO 2020 lures newcomers to bunker sector, profit is far from guaranteed: Fuel for Thought

A pharmaceutical company’s ill-fated attempt to focus on trading bunker fuel derivatives highlights the unpredictability that IMO 2020 has injected into oil markets.

Having sold off its opioids business the previous year, in early 2018, Norway’s Vistin Pharma announced it would set up a new oil trading unit focusing on profiting from the International Maritime Organization’s lower sulfur limits for shipping in 2020. Ten months and $9.8 million of paper losses later, the company said in early January that it would be closing the unit.

Vistin had bet on the spread between gasoil and high sulfur fuel oil in Singapore widening in the run-up to 2020, when fuel oil demand is set to plummet as the IMO prompts shipowners to shift to cleaner-burning fuels.

Singapore fuel oil prices vs gasoil

In a presentation from September 2018 on the company’s website, it projected the spread widening to as much as $800/mt by the end of 2020.

But the strategy appears to have been foiled by a combination of last year’s strength in fuel oil prices and the rapid drop in crude prices in the fourth quarter.

By December 31, the 150,000 mt of contracts the company held represented a mark-to-market loss of NOK 85 million ($9.8 million). Vistin’s head of energy trading resigned at the start of the year, and after a swift strategic review, the company decided to shutter the unit he had set up.

Not as easy as it looks

The episode highlights the dangers faced by some of the outside players currently eyeing up the bunker industry for money-making opportunities in 2020.

On paper the changes coming next year look easy to profit from: a sharp drop in fuel oil prices towards the end of 2019 and a more steady rise in middle distillates looks all but inevitable, and is potentially not yet fully priced into the forward curve.

Go deeper: Explore S&P Global Platts’ content on IMO 2020

But Vistin’s difficulties show how some of the less-familiar moving parts around IMO 2020 may make it tricky for new money to enter the bunker industry and take advantage of the regulatory disruption.

The scale of last year’s fuel oil strength was unexpected: a combination of sinking Russian output and firm Saudi demand left the bottom of the barrel briefly trading above gasoline prices in Singapore towards the end of 2018.

Investments in emissions-cleaning scrubber equipment may be another area where outside money gets tripped up by some of the nuances around how 2020 plays out.

Ships have the option of paying a few million dollars to install a scrubber that cleans their emissions and allows them to continue burning fuel oil, and financial institutions including Goldman Sachs have shown interest in financing these investments and profiting from the potential fuel bill savings to be made.

Scrubbers fall out of favour

But in recent months, the scrubber industry has been taken aback by a series of regulatory decisions against open-loop models of the technology — a type of scrubber that deposits sulfurous wash water back into the sea.

It recently emerged that China would be likely to ban the use of open-loop scrubbers in some of its waters, following a similar decision by Singapore last month, raising the prospect of those that have invested in — and financed — this equipment finding themselves unable to profit from it across large parts of Asia.

This isn’t to say that turning a profit will be impossible in 2020. Vistin Pharma’s bet may yet pay off to some extent.

The company has decided to hang onto its bunker derivative investments, and they may look less disastrous later this year as fuel oil’s recent strength wanes.

But outsiders coming to this industry for the first time in the run-up to 2020 will need to be wary. The bunker and shipping industries are anything but simple, and involvement with them is not for the faint-hearted.

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Hitachi’s U-turn on UK nuclear plant could be a blessing in disguise

Hitachi’s decision to down tools on its proposed GBP16 billion ($20.6 billion) nuclear project in Wales, announced on January 17, could be a blessing in disguise for British consumers.

Instead of further subsidizing a globally declining industry, the government has simpler alternatives to ensure long-term energy security and affordable electricity prices for all. Natural gas, more renewables, storage and demand response are cost-efficient solutions with significantly lower risk than bankrolling the potentially ruinous cost of atomic fission.

The suspended project was to be built at Wylfa Newydd on the Welsh coast by the Japanese industrial giant and scheduled to be operational by 2027. Designed to produce 2.7 GW of electricity, it would have generated more than enough power to meet the demand of a city the size of Manchester, or keep 100 million lightbulbs turned on for a year.

Losing the project has raised concerns about the long-term future of nuclear power in the UK. Its cancellation follows the abandonment by Toshiba in November of the 3.4 GW Moorside project in Cumbria. The loss of these projects reduces the number of planned plants to three – the GBP18 billion Hinkley Point C being built near Bristol and two projects at Sizewell in Suffolk and Bradwell in Essex.

“Removing Wylfa Newydd from our nuclear capacity assumption means we now only see Hinkley Point C coming online before 2030,” said S&P Global Platts Analytics. “Without it, UK nuclear capacity would fall to 5.7 GW in 2028 [from 8.8 GW today], due to the closure of Hinkley Point B, Hunterston B and Dungeness B coupled with the reduced view in new build growth. Along with further nuclear closures at the start of 2030 nuclear capacity could fall to 5 GW by 2032.”

Despite these setbacks, the government says it remains committed to nuclear to help meet the UK’s future power demand needs. “This government continues to believe that a diversity of energy sources is a good way and the best way of delivering secure supply at the lowest cost, and nuclear has an important role to play in our future energy mix,” said Greg Clark, Minister of State for Business, Energy and Industrial Strategy in a statement to Parliament following Hitachi’s decision.

According to the National Grid’s Future Energy Scenarios report, Britain may require generation capacity to rise to as much as 268 GW by 2050, from 103 GW installed today. Driving this growth in demand could be a dramatic shift in passenger transport. The number of electric vehicles driving on Britain’s roads and plugging into the network for a recharge could increase to 36 million cars by 2040, up from about 200,000 at the end of last year. This transport revolution could make nuclear essential to Britain’s long-term decarbonized energy mix.

This is the view of many industrialists and energy experts. Nuclear plants are a dependable source of low carbon baseload electricity, meeting 24/7 demand while renewables and flexibility manage the rest. Nuclear helps meet climate targets. An atomic power plant produces hardly any carbon emissions compared with natural gas or coal. Britain’s power industry carbon emissions would increase by 10% at least if all nuclear plants were replaced by gas.

“As coal is taken out of the equation in the next few years and the existing nuclear fleet reaches the end of its natural life after 50 years, decisions are already long overdue for construction to be completed in time and not leave the country at risk of power cuts or reliant on imported electricity, much of it from unreliable regimes,” said Justin Bowden, GMB union National Secretary for Energy, following Hitachi’s decision.

But nuclear carries its own risks. Disasters like Chernobyl in 1986 and more recently Fukushima, although rare, live long in people’s memories. This helps explain why nuclear power’s share of global electricity supply is falling, down from a peak of 17.6% in 2006, to just over 10%in 2017, according to research from Chatham House.

“While the Chernobyl and Fukushima accidents undoubtedly raised public and political concerns over nuclear safety, the main obstacles to deployment in most markets are difficulty of financing and lack of economic competitiveness,” wrote the London-based think tank.

Finally, there is the cost of building nuclear plants and the significant subsidies developers demand for their construction. The government was obliged to offer EDF expensive incentives to go ahead with the Hinkley Point C project in Somerset. Under the terms of the deal, the developer has been guaranteed a strike price of GBP92.50/MWh  for the power generated for 35 years in addition to compensation for any early shutdown and a government credit guarantee for bonds to finance the scheme.

The government was prepared to offer Hitachi a strike price of no more than GBP75/MWh to proceed with Wylfa in addition to debt financing but “despite this potential investment, and strong support from the government of Japan, Hitachi have reached the view that the project still posed too great a commercial challenge,” Clark told Parliament. Hitachi will absorb a GBP2.1 billion loss on the project.

Building gas-fired generation is the simplest alternative. The world is awash with the fuel, which is flexible, relatively clean compared to coal, and competitively priced for consumers.

For Hitachi’s GBP2.1 billion loss on Wylfa’s stalled development, 4 GW of combined cycle capacity or at least 600 MW of offshore wind could have been built.  Meanwhile, the UK’s increasing pool of renewable assets took a 33% share in total generation last year. With the help of battery storage, demand response and flexible generation, UK renewables will continue to reduce the need for fossil-fired and atomic generation.

Better electricity storage technology likely to be developed over the next 20 years and smarter networks could also make renewables more reliable. Although these may not be enough to provide the vital baseload security nuclear can guarantee, there are still cheaper ways to keep Britain’s lights switched on.

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Geopolitical tremors mean a choppy outlook for oil in 2019

Get used to more scary oil market volatility in 2019. This is the message coming from leading industry strategists and forecasters after a bruising end to last year, when Brent crude dipped below $50/b.

Although the benchmark has recovered along with major global stock markets, forecasters are concerned about the prospects of a sustained rebound. Unpredictable geopolitical upheavals like Brexit and US President Donald Trump’s trade wars are expected to weigh more heavily on sentiment than the fundamentals of supply and demand.

“One of the key lessons learned in 2018, painfully by some, is that market sentiment can shift violently without much change in fundamentals, requiring a steady, holistic perspective,” said Chris Midgley, global head of analytics, S&P Global Platts. “It is clear that this volatility will remain a feature across the energy markets in 2019.”

Global demand is becoming harder to predict. The world consumed on average a record 100 million barrels per day of crude in 2018 but the positive outlook is being clouded by weaker economic growth. The Paris-based International Energy Agency (IEA), in its final market report of the year, kept its demand growth figure unchanged at 1.4 million b/d, blaming a weakening economy for offsetting the otherwise positive environment for oil consumption caused by weaker prices.

Meanwhile, stockpiles of unwanted crude linger in tanks around the world. Inventories in OECD industrialized economies continued to build in October for a fourth consecutive month by 5.7 million barrels to an ocean of almost 2.9 billion barrels, according to the IEA. The build sent stockpiles above their five-year average for the first time since March.

“Fundamentals in the oil market look bleak, with slowing economic growth and weaker-than-expected demand pushing the market firmly into bear territory,” said Ashley Kelty oil and gas research analyst at Cantor Fitzgerald Europe.

On the supply side, there is also little cause for certainty. Forced on the defensive, OPEC and its allies led by Russia are cutting output by a combined 1.2 million b/d. However, delivering on their pledges may be hard to achieve given the tough economic conditions many members now face.

Saudi Arabia – the world’s largest exporter – requires prices to trade above $80/b to balance its bloated state budget. The kingdom remains locked in a bitter cycle of dependence on oil rents despite repeated efforts to diversify its one-dimensional economic model. Riyadh shaved over 400,000 b/d off the country’s production last month in a bid to jolt some life back into prices, according to the latest Platts OPEC production survey.

However, OPEC’s discipline and success still depends on the continued co-operation of Russia.

The Kremlin has cautioned against the alliance – which controls 40% of the world’s supplies – from making any hasty decisions in response to crude’s rout. However, after years of falling back on their foreign currency reserves to support their economies, few producers in the Gulf region have much financial room to maneuver.

Complicating their task further are US producers whose success has undermined the cartel’s power in oil markets. US crude production is forecast to bust through 12 million b/d in 2019 despite lower prices forcing some operators to cut capital expenditure budgets and rig counts beginning to ease.

The number of active permits to drill – which indicates the strength of future activity – end the year at their highest level since 2013. The big question is how long can US output continue to grow and remain economic for operators? OPEC’s tried to answer the question in 2014 when, led by Riyadh, it launched a poorly executed price war to slow down its booming North American rivals. But the tactic failed spectacularly.

Andy Critchlow talked to CNBC about oil market trends in late December

Nevertheless, some analysts have started to question the resilience of US producers – many laden with debt and facing rising operating costs – to continue competing and growing at current price levels.

“If prices remain at these levels for a sustained period, North American producers are likely to begin curbing investment and production growth. That said, the Saudis, the backbone of OPEC+, are already leading by example and have already scaled back their exports this month. We expect improving oil inventory dynamics – primarily in the US – to support oil prices over the coming months,” wrote Giovanni Staunovo, oil analyst at investment bank UBS.

Disruptions to supply are more likely to come from more exotic locations. Venezuela’s oil industry is on its knees and the country’s oil minister Manuel Quevedo – a former brigadier general – will take over OPEC’s rotating presidency in 2019.

The South American producer pumped 1.17 million b/d in December, according to the latest Platts OPEC production survey, down 630,000 b/d year-on-year. Elsewhere, the political situation in Libya remains combustible with the threats to its oil infrastructure from rogue militias a regular ongoing occurrence. Of course less oil from either Venezuela and Libya flowing onto markets could be a short-term blessing for prices but it also could be a sign more frightening volatility is ahead.

This article was previously published as a column in The Telegraph

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Less volatile gas prices give newest US LNG plant smoother start-up

US LNG export projects, whether brownfield or greenfield, are multi-year, billion dollar projects. While construction timelines dictate their commissioning schedule, there can be inconvenient and convenient times in the unpredictable natural gas market to begin this testing.

The two most recent additions to the US fleet of natural gas liquefaction and export facilities – Cove Point LNG and Corpus Christi LNG – demonstrate this. They began operations about one year apart during the winter months, when gas prices are typically elevated, but disparate conditions over the two winters meant vastly different feedgas costs in the critical ramp-up phase.

Corpus Christi, located in Texas, is the latest facility to begin commissioning. It has been making progress toward commercial operation at Train 1 following that train’s first cargo export onboard the Maria Energy, December 11. Meanwhile, its second train recently received Federal Energy Regulatory Commission approval for fuel gas introduction.

Corpus Christi facility has enjoyed unusually low 2018-2019 winter gas prices in the Southeast and East Texas. Henry Hub’s cash settlement on Thursday January 3, 2019 priced at $2.685/MMBtu, its lowest price back to May 4, 2018, when it was trading at the same price. Prices since then have climbed back above $3/MMBtu, trading at $3.36/MMBtu on January 14, a three week high.

S&P Global Platts Analytics data shows that flows for the January 4 and 5 gas days were record-setting, with total US LNG feedgas demand reaching 5.5 Bcf/d, including feedgas demand pull from Sabine Pass, Cove Point and Corpus Christi.

US LNG feedgas deliveries by terminal

One year ago, the US gas market dealt quite a different hand to Maryland’s Cove Point facility during its commissioning period.

On January 3, 2018 Henry Hub’s cash price spiked to $6.875/MMBtu, its highest cash price of 2018.

Cove Point ended up being delayed with its lone Train 1 commissioning. Data from Platts Analytics showed LNG feedgas demand pull didn’t kick in substantially until January 31, 2018 when 206 MMcf/d of feed gas flowed to the facility. On that date, Transco Zone 5 priced at $4.58/MMBtu and Transco Zone 6 non-NY was $4.62/MMBtu.

Dominion, the owner of the Cove Point facility, blamed the delays on “typical start-up issues.”

This start-up delay occurred at a time in January when there were also record cold temperatures in early 2018 that led to cash prices above $100/MMBtu. Transco Zone 5 and Transco Zone 6 non-New York on January 4, 2018, spiked to $127.00/MMBtu and $124.735/MMBtu, respectively, the two locations’ highest cash prices ever. Cove Point’s first cargo ultimately was shipped in March 2018.

Cash natural gas prices are certainly not the only factor affecting for terminal start-up schedules, but LNG facility commissioning timelines could be impacted by the volatile prices of the winter natural gas market.

Platts Analytics data shows that Cove Point had the longest duration in days, of any recent US lower 48 liquefaction train, between FERC fuel and feedgas approvals to first significant (100 MMcf/d) flows at 299 days from their fuel gas approval and 153 days from their feedgas approval.

In comparison, Cheniere’s Corpus Christi Train 1 had 139 days between its fuel gas approval and significant flows above 100 MMcf/d. Even shorter, at 55 days was its feedgas approval timeline to significant flows, Platts Analytics data shows.

While Cove Point only has one train at its facility, Corpus Christi’s continuing progression in the commissioning of its second train may be helped by historically low natural gas prices that have returned to Texas and the Southeast this winter and at the start of 2019.

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Insight from Shanghai: Waking up from the Chinese dream

There have been better starts to the New Year. The December Caixin Manufacturing PMI, a survey of Chinese manufacturing activity, contracted for the first time in 17 months. Soon after, reports began to emerge that China’s growth target will be lower than that set for 2018.

Apple, once the world’s most valuable company, sent shock waves across financial markets. It revised down its earnings for the end of 2018 citing an economic slowdown in China that was significantly greater than they had anticipated due to weak demand and the impact of trade tensions with the US.

While the dispute with the US has undoubtedly affected sentiment, with December data showing trade to the US weakening, over most of last year Chinese exports to the US were actually very strong. Exports to the US grew 11% in dollar terms in 2018 and it was government efforts to rein in the growth of credit that had a greater direct impact on the economy. As liquidity tightened last year sales of real estate and automobiles turned negative as companies and individuals found it harder to borrow money.

The chart below shows that as credit – represented by Total Social Financing – tightened last year  sales of real estate and automobiles turned negative as companies and individuals found it harder to borrow money.

Credit drives Chinese auto, housing sales

Out of the shadows

Since the financial crisis China has been increasingly reliant on debt to maintain economic growth. At the start of 2009 Chinese credit to the non-financial sector – debt owed by the government, households and companies – was slightly more than one and a half times the size of the economy. By the end of 2018 this had grown by 65% to more than two and a half times GDP. This is much faster than any other major economy. Even Japan, the world’s most leveraged major economy, only saw debt as a percentage of GDP grow by 14% over the same period.

It’s little wonder that the authorities were concerned. Such was the vulnerability of the economy to this rapid accumulation of debt, that starting mid 2016 the government has been engaging in a process of deleveraging the industrial sector and tightening credit across the economy.

Last year saw a particular focus on curtailing lending by China’s shadow banks, financial companies outside the conventional banking sector that engage in bank-like lending activity. Not all shadow bank activity is, well, shadowy. But there is little transparency around their activity or the potential risks that they might pose the financial system, and some shadow banking activity has been significantly curtailed by the most recent credit tightening cycle.

This has had little effect on the large state-owned enterprises that dominate the energy and commodity sectors. Their links to the state-owned banks mean they have little problem obtaining finance. The impact has been greater at smaller, private, companies down the value chain like metals fabricators, traders, and even independent refiners which are unable to easily obtain credit from the state owned banks. Already contending with tighter environmental inspections, a clampdown on tax evasion, as well as slowing demand, tighter credit conditions have caused a wave of bankruptcies across the private sector.

Real estate to the rescue

A move to shut down online peer-to-peer lending platforms, a small but fast growing part of the shadow credit sector, has also constrained consumer access to finance. With analysts estimating that peer-to-peer lenders financed as much as 15% of new vehicle sales in 2017, the contraction in the sector was a major contributor to the sharp fall in sales in the second half of last year.

Indeed 2018 was the first year in decades that new car sales were down on the previous year, impacting demand for flat steel and gasoline. With the government announcing that it will not provide relief to the auto sector by cutting purchase tax for passenger vehicles as it did in 2015, gasoline demand is expected to continue to be weak. Platts Analytics expect Chinese gasoline demand to grow at under 3% in 2019,  down from 6% in 2017.

Given this backdrop, it was somewhat surprising that the property market, that bellwether of the economy, was so resilient last year. It underpinned steel demand which grew at a robust 8% over the previous year in the first eleven months of 2018. With the clampdown on P2P lending platforms and a 30% fall in the Shanghai Composite index, money flowed into investment property last year, especially in smaller cities where there are fewer restrictions on purchasing investment properties. But with prices softening and home sales falling the outlook is less optimistic for 2019. This appears to have been priced into the steel market where the price of construction rebar has fallen by nearly 20% since the end of October.

Chinese steel prices weakened in late 2018

Did someone say stimulus?

As we move into 2019 the signs are that the government will continue down this ascetic path. It has approved $125 billion of new rail projects and will free up an estimated $117 billion for new lending by cutting the amount of cash banks are required to hold on reserve. But the effect of this on the economy and commodity demand may well be more muted than the headline numbers might suggest.

The government has announced a range of tax cuts to support the economy, especially small businesses. Some tinkering around the edges to support the property sector, like the lifting of some of the restrictions on secondary property purchases in larger cities, also seems likely. And policies to increase passenger cars and white goods are also imminent, according to comments by an official from the National Development and Reform Commission quoted by Chinese media last week.

In early January, some analysts were calling for stronger measures from Beijing to boost the economy. But the government is likely to tread carefully so as to channel any new lending to support smaller, private sector enterprises, not fuel a speculative property bubble as it did in 2012 and 2015.

The question is whether the government can stay the course on its debt reduction goals. An early resolution of the trade dispute with the US would certainly provide some relief to the economy and help mitigate some of the spillover from the tighter credit conditions.

The government has only just finished cleaning up the mess left over from the last decade of credit excess which left the country with industrial overcapacity and a glut of unwanted property. Another credit splurge would see debt compared to the size of the economy rise beyond even that of the Eurozone. Only Japan’s economy would be more leveraged, and China certainly doesn’t want to go down that path. Japan’s economy has gone virtually nowhere since the 1990s.

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In the LOOP: US crude exports to Europe driven higher by spreads, tanker rates

Favorable freight economics have helped drive up demand for light, sweet US crude oil in Europe and an expanding list of countries, including Germany, are looking to import barrels from the US Gulf Coast.

USGC-to-Europe crude flows have been on the rise recently, with some market participants expecting up to 800,000 b/d to land in Europe in March. At least 5.2 million barrels (roughly 740,000 b/d) of crude was sent from the US to Northwest Europe and Mediterranean during the week ending January 11, according to S&P Global Analytics data.

In October, the latest month for which data is available, an average 580,000 b/d of US crude was sent to Northwest Europe and the Mediterranean, according to the Energy Information Administration. Rotterdam is the main destination for US oil in Europe and an average of 1.7 million barrels a week has flowed into the Netherlands from the US during the past six weeks. The UK is also a major destination, averaging about 1 million barrels a week during the past six weeks. There has been a noticeable increase in flows to Italy, with about 1.5 million barrels arriving there for the week ending January 11. That is about triple the amount what was sent in the weeks prior.

While crude netbacks have not been a particular driving force to move more US crude to Europe, price spreads have. Prices of Forties in Europe and delivered WTI have been at or near parity on a delivered basis from October to the present. When the two are at parity it does not present any hurdles to the arb.  However, the arbitrage to move US crude to the Mediterranean has likely been incentivized by increased discounts compared to competing grades. WTI delivered to the Med averaged a near $2/b discount to Azeri Light over a similar period, and a near $3/b discount to Nigerian Bonny Light, according to S&P Global calculations.

The Netherlands and Italy are not the only countries bringing over more US crude. In a rare move, two cargoes of US crude recently were sent to Germany. The Southport, an Aframax-sized tanker, loaded 540,000 barrels of US crude in Ingleside, Texas, on January 6 and is headed to the German port of Wilhelmshaven. Another Aframax, Searanger loaded in Houston last month and made the trip to Germany, arriving in Brunsbuttel on December 24. It is unclear which refiner was the buyer of the US crude in Germany as both ports are large storage points and are connected to pipelines that may transport oil to other European countries, sources said.

While smaller tankers typically carry US crude to Europe, over the past two weeks, there has been an increase in the number of larger VLCCs and Suezmaxes on the USGC-UK Continent or Mediterranean route as charterers looked to the larger ship classes to carry crude cargoes to Europe. European refiners typically prefer the 500,000 barrels carried on Aframax vessels in comparison to the 1 million barrels on Suezmaxes and 2 million on VLCCs. But recent rate economics have made VLCCs nearly half of the cost per metric ton of taking an Aframax.

There have been at least six Suezmaxes and four VLCCS placed on subjects to carry crude from the US to Europe since the market returned from the long holiday weekend on January 2, compared to eight Aframaxes. No VLCC had carried a US cargo to Europe until the Olympic Lady set sail from Corpus Christi Lightering, heading to Rotterdam with an Occidental Petroleum cargo December 24. Most recently, Oxy booked the Hong Kong Spirit to make a 270,000 mt USGC-Singapore run at a lump sum $6.15m with options to China at $7.15m and the UK Continent at $4.0 million.

There is expected to be a shift back to Aframax vessels as rates have fallen Worldscale 47.75 points, or $8.73/mt, since January 2, last assessed Monday at w115, or $21.05/mt. The arbitrage opportunity for US crude shipments, taking into account Aframax freight rates, has opened up following the drop, sitting at 72 cents/b for exporting WTI crude into Northwest Europe and $1.05/b for Eagle Ford.

British oil giant BP continued to show bids for US crude oil during the London Market on Close process on Monday, but no trades were heard done. BP had also made several bids for WTI Midland delivered to Europe last week. The standing bid on Monday was for 650,000 barrels to be delivered DAP basis Rotterdam between March 9-13, and was pricing flat to Dated Brent. BP also placed a bid for Eagle Ford 45 API crude. WTI Midland barrels expected in the Mediterranean in March were talked late last week in London at Dated Brent plus between 20-50 cents/b, depending on delivery dates.

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Shell pops the hood on its energy transition strategy: Fuel for Thought

The internal combustion engine faces an expiry date as the transportation sector moves decidedly towards electrification. Plastics and heavy transportation will not sustain high oil demand on their own.

The question is whether the inevitable energy transition from liquid transportation fuels to electricity will take a few years or several decades. Either way it poses an existential threat for oil companies.

For oil majors, the latest climate-related setback has been financial in nature, with institutional investors, including sovereign wealth funds, concerned about long-term positions in fossil fuels.

In October 2018, BP’s Bob Dudley publicly defended oil majors, in light of fossil fuel divestments and concerns that oil assets could be written off at scale if the energy transition were to accelerate. He argued that oil companies are best placed to lead the energy transition.

When Norway’s Statoil changed its name to Equinor, oil traders joked that it sounded more like a pharmaceutical company, but they also acknowledged the hard realities behind the oil major’s shift toward becoming an energy company.

The supermajors have an unenviable task ahead — timing their diversification strategy right, ensuring current supply is not disrupted, continuing to pay high dividends and implementing a transition plan that ensures survival.

How exactly this will be achieved has been tough to gauge. In late December 2018, Shell’s Executive Vice President of New Energies, Mark Gainsborough, popped the hood on the company’s energy transition plan and answered some burning questions.

Declaration of intent

Shell started its New Energies segment in 2016 to invest in two new businesses — new transportation fuels and the power sector, targeting returns in the high teens and around 8%-12%, respectively.

Gainsborough said the oil major will pump $1 billion-$2 billion in New Energies every year out of its annual capital expenditures of $25 billion. “But the expectation is if we find good commercial opportunities over time we can look at ways of ramping that up,” he said, adding options to include M&A and organic growth.

The New Energies business will be monetized in the same manner as shale, natural gas and deepwater drilling have been. Natural gas and deepwater drilling have already become cash generators, shale is next, and New Energies will follow, Shell said.

“The bottom line is over the next 20 to 30 years we need the cash from the conventional businesses to fund growth and new opportunities like New Energies,” Gainsborough said.

He said Shell also plans to link executive remuneration to reductions in the carbon footprint and “really hard-wire this into the thinking of the company.”

Chasing power, and scale

One of the key concerns about the energy transition of oil majors has been scale: Conventional oilfields cost several billions of dollars, but a solar or wind farm costs a fraction of that.

“I think if we wanted to be on the same scale of business as we are today, it’s almost inevitable that you would have a bigger power business,” Gainsborough said. “We really want to scale that business up quite materially.”

Shell’s plans to dominate the power sector from generation to household charging systems – imitating its “downstream heritage” in fuel distribution like petrol stations. Aggregating hundreds of smaller renewable projects could also make up for big megaprojects.

Shell is also replicating its US power trading business, where it is the second-largest power trader in terawatt hours, in Asia Pacific – similar to oil, Gainsborough said.

The challenge is that oil majors are attempting to enter a completely different business with incumbents, and one that’s heavily regulated in Asia. How this plays out remains to be seen.

Pragmatism on fossil fuels

The new business model for oil majors will be driven by the carbon intensity of the products they sell, and not just the carbon footprint of their operations. The new energy businesses are being positioned so they can be rapidly scaled up if fossil fuels decline rapidly.

Shell was confident oil will not disappear overnight and natural gas will be vital in the energy transition.

Gainsborough said there are overlaps, too, such as using offshore and deepwater expertise in offshore wind and floating renewables.

In Queensland, the oil major is combining a large-scale 200 MW solar farm with an existing combined cycle gas turbine. The project is yet to reach a final investment decision, and could save gas for the domestic gas market.

Shell is expanding its venture capital business into Shanghai to take advantage of the early stage investments in new technologies and startups, given the innovation boom in China in particular. Its new fuels business is also looking at biofuels, hydrogen and battery charging.

Hydrogen is seeing growing corporate and government interest. In October 2018, Japan’s trade ministry backed a ministerial-level meeting on using hydrogen as a fuel source in Tokyo, the first of its kind.

“We’ve been busy building hydrogen stations, mainly in California and in Germany, which we see as the two lead markets for hydrogen,” Gainsborough said. “But we’ve [also] done a few stations in the UK and some in the Netherlands and a few other markets.”

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Aramco’s IPO looks believable again after Saudi speaks up about reserves

Saudi Arabia has finally silenced its peak oil critics and simultaneously revived interest in its stalled $2 trillion plan to IPO state-owned producer Aramco.

The kingdom revealed last week it has enough crude to pump at current rates for at least another 70 years. At the end of 2017, Saudi oil reserves stood at an eye-watering 268.5 billion barrels, up from previous estimates of 266.4 billion. By comparison, the UK’s remaining cache of commercially retrievable oil under the seabed of the North Sea could be almost completely drained in a couple of decades.

The updated figures were no surprise for many experts. BP’s highly respected Statistical Review of World Energy lists Saudi oil reserves at just over 266 billion barrels and Rystad Energy estimates that 276 billion barrels remain under its Arabian deserts. However, not everyone has been convinced by either the longevity, or scale, of Saudi’s remaining oil riches.

In his critically acclaimed 2005 book “Twilight in the Desert”, the then prominent oil economist Matthew R. Simmons predicted that Saudi Arabia’s oil wells were about to run dry. His theory was based on the aging status of several gigantic oil fields, which still provide the bulk of the kingdom’s near 11 million barrel per day output.

Simmons triggered a wave of paranoia, which Riyadh had failed to entirely dispel until now. After all, oil production in the kingdom dates far back to 1938 and the drilling of its first commercially viable well in Dammam. Although the original bore hole is enshrined at the center of Aramco’s headquarters in the Eastern Province, the company is still squeezing barrels from the deposit.

Secrecy deters investors

Instead of running out of oil, Saudi Arabia’s bigger problem is a deficiency in transparency. Its reserves have rarely been publically updated, or audited by an independent third party until now. Doors to the data rooms of Aramco — which is responsible for almost its entire national output — have been tightly locked. The reason for this new spirit of openness could be Aramco’s proposed IPO.

The plan to sell a 5 percent stake in Aramco to international investors in order to raise a potential $100 billion windfall for Saudi has been beset by problems. The initial exuberance of international bankers for the deal, which could create the world’s most valuable listed company, was replaced almost immediately by cynicism. Aramco’s accounts were “too opaque”, they said, and the amount of revenue the government was willing to share with investors unclear.

A decision about where the company’s shares outside Saudi would be listed went unresolved and crucial advisory appointments remained unfilled as the deadline for issuing a prospectus approached. Tepid oil prices were also making the IPO much less appealing. Technocrats at Aramco’s headquarters may have hoped the entire plan would be shelved indefinitely as more people began to question the $2 trillion valuation desired by the kingdom’s Crown Prince Mohammed bin Salman.

Data release could change minds

One delay led to another, until the world’s financial community finally gave up believing it would ever happen at all. Some of their faith may have been restored by the update of the kingdom’s oil reserves, which underscores both Aramco’s potential value and strategic importance as a global energy supplier, but also the government’s desire to maximize its most prized asset.

“Every barrel we produce is the most profitable in the world, and why we believe Saudi Aramco is the world’s most valuable company and indeed the world’s most important,” said Saudi oil minister Khalid Al-Falih in a statement posted on the state news agency’s website.

According to the latest survey by S&P Global Platts, Aramco pumped over 10.6 million barrels per day of crude last month, making it by far the world’s single largest producer.  It is also one of the most efficient. Al Falih said Aramco’s oil costs just $4/b to produce. It’s a key figure for potential investors, which could make its $2 trillion valuation more believable. Suddenly, the IPO looks plausible again.

The fact is oil markets are more likely to dry up before Aramco’s reserves of crude run out. Demand for oil remains robust despite the growing popularity of electric vehicles and the pressure of climate change forcing consumers to search for cleaner transportation fuels. Last year, the world consumed 100 million b/d for the first time in history and consumption is expected to continue rising at least through to 2040, although beyond this date the outlook is harder to predict.

Unless it wants to flood the market and send oil prices tumbling, Saudi Arabia’s best option if it wants to maximize its vast remaining hydrocarbons reserves could be to sell off increasingly large shares of Aramco to international investors no later than 2021. Otherwise it runs the risk of having to leave much of its wealth stuck in the ground.

This article was previously published as a column in The Telegraph

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EU carbon price volatility in January a sign of things to come

EU carbon market analysts in December 2018 predicted that sharp price volatility seen in the second half of the year would continue into 2019. As of early January, they’ve been proved right.

After surging close to 10-year highs of over Eur25.00/mt ($28.65/mt) in December, carbon prices crashed back below Eur22.00/mt in the first few days of January.

And that’s likely a sign of things to come in the rest of 2019 as the market grapples with highly significant factors, both bullish and bearish, that are certain to shape price formation this year.

In short, a now more finely-balanced carbon market will lead to increased price volatility because a smaller cushion of surplus supply will leave prices more sensitive to demand-side changes.

Europe’s flagship policy tool to reduce carbon dioxide emissions from power plants, factories and airlines got a major regulatory overhaul in 2016-2018, after the EU passed key measures into law. Those included the Market Stability Reserve, which reduces a long-term surplus of carbon allowances by 24% per year from 2019-2023, helping to re-balance the market and propelling prices to 10-year highs in 2018.

Mild weather restrains prices

At prices of Eur4.00/mt to Eur8.00/mt in 2017, carbon made little difference to the economics of fuels for power generation. That all changed in late 2018, with carbon prices of above Eur20/mt beginning to help cleaner natural gas-fired plants push older emissions-intensive coal units out of the merit order for power generation.

With the MSR’s supply constraints arguably priced fully into the market by the end of 2018, prices fell back in early January amid a raft of bearish factors including a milder than normal start to winter in Europe – reducing heating demand against expectations – and lower gas prices for summer 2019 which indicate a lower implied carbon price required to prompt coal-to-gas fuel switching.

EUA nearest December price

That’s a big change from 2018, when coal-fired profits in continental Europe were comfortably higher than equivalent gas-fired margins, even for lower efficiency coal units, maintaining strong hedging demand for carbon among the utilities.

The lower carbon prices in the first few days of January gave the bulls reason to pause for thought: January is likely to be among the tightest months of the year on the supply side, with German auctions on hold until February and no UK auctions in Q1 due to Brexit.

If prices fail to move higher in the remainder of January, this could be taken as a bearish sign in the short-to-medium term, as auction supply will rise in February with the return of German volumes. This is likely to have kept bullish momentum in check at the start of the year.

Poland in early December said it plans to increase its planned auctioning volume in 2019, by adding a volume of 55.8 million mt left over from a pool set aside for free allocation to help modernise its power sector. Those volumes will be spread across 2019, starting with Poland’s first auction set for January 16.

Seasonal factors are also in play: as of the second week of January, very cold winter temperatures had yet to arrive in Europe, but any repeat of 2018’s “beast from the east” would be expected to drive demand for domestic heating, pushing power, coal, gas and carbon prices higher.

Global gas price influence

Brexit also remains a risk, with any hard UK exit from the EU in March posing a downside risk for carbon demand from UK plant operators, while agreement on a deal would maintain demand by keeping the UK in the EU ETS until the end of 2020. UK lawmakers are set to vote on the draft UK-EU withdrawal agreement on January 15.

Some analysts have taken a bearish tone on the price outlook, pointing to Brexit risks and weaker gas prices for the time being, which help to make the fuel more competitive against coal.

“The main barrier to further upside in the coming two weeks is the Brexit vote, although even if the parliament rejects the current deal, the full implications for the EU ETS are far from clear,” said energy analyst Trevor Sikorski at research group Energy Aspects, in a note January 7.

“The long-awaited tip of the global gas market into oversupply is showing some evidence of happening now, which is helping drive gas prices down and is already pushing more gas into merit in continental European markets,” he said.

“A real downside concern for EUA prices in the coming two years is if gas continues to soften relative to coal, as this will drop the implied carbon price needed to get all of the fuel switch done, providing more [CO2] abatement at a lower price,” said Sikorski.

On the flip side, the market short driven by the MSR in 2019 could be bigger than the CO2 abatement achieved through coal-to-gas fuel switching, re-igniting the bullish price trend seen in 2018.

“Still, even exhausting the fuel switch is unlikely to balance the EUA market, requiring some net draw from the credit inventory in the market,” he said.

So there you have it. For carbon prices, a lot will depend on European gas prices in 2019 and their relative value against hard coal.

But whether or not carbon prices will gravitate around the Eur20.00/mt level or move to a higher pricing environment in 2019, as many analysts expect, the days of single euro digit carbon prices are gone.

Stronger carbon prices are set to play a much more prominent role in a switch to cleaner power generation fuels this year, boosting the economics of gas-fired and renewable energy generation and denting power sector demand for hard coal.

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Trump steel tariffs persist in 2019, but quotas could provide wiggle room

US President Donald Trump’s administration rocked the global steel market in 2018, with the introduction of a 25% tariff on steel imports that changed trade flows and set off a chain reaction of retaliatory tariffs and additional safeguard measure from other countries.

With the tariffs still in place, 2019 is looking to be another turbulent year for steel as the US heads into fresh trade negotiations with major markets including Japan and the EU. Meanwhile, the trilateral deal with Mexico and Canada reached in 2018 still has details to be ironed out.

In the first two years of his presidency, Trump has relied heavily on tariffs as leverage to rebalance US trade and negotiate new trade agreements. In December he even referred to himself as a “Tariff Man” on Twitter, a moniker befitting his trade policies.

Since January 2018, the Trump administration has placed tariffs on solar panels, washing machines and tariffs of 10%-25% on $250 billion worth of Chinese goods. The Department of Commerce is also conducting Section 232 investigations into automobile and uranium imports, which could lead to further tariffs should the department find imports of these products are a threat to US national security. That was judged to be the case for steel and aluminum, when Trump in March announced the US would begin collecting a 25% tariff on steel imports and 10% tariff on aluminum imports under Section 232.

US raw steel production 2018

As intended, the policy has helped to boost US raw steel production (see chart), although the wider effects are contested. But as much as Trump favored tariffs in 2018, it is likely 2019 could see him shift from being a “Tariff Man,” to a “Quota Man,” or at least that is the expectation in the US steel market.

Trump’s wall casts shadow over USMCA

Since the Section 232 steel tariffs took effect on steel imports March 23, only four countries have been able to work out agreements with the US for their removal. Argentina, Brazil and South Korea each agreed to quota arrangements in lieu of the tariffs, which cap imports from those countries at a specific level, while Australia is not subject to the tariffs or a quota.

Throughout the back half of 2018 there was a growing expectation in the domestic steel market that the US would continue to reach quota agreements on steel imports, particularly with some of its closest trading partners, however the White House has been mum on where discussions currently stand.

The US in October reached an updated trilateral trade agreement with Canada and Mexico, known as the United States-Mexico-Canada Agreement, which Trump has said would not have been come together without the US applying tariffs on steel and aluminum imports from those countries.

“Without tariffs we would not be talking about a deal,” Trump said announcing the trade agreement in October, though Canadian Prime Minister Justin Trudeau has disputed this claim.

All three countries said they would continue negotiations regarding the metals tariffs, and Trump has signaled the US would be open to their removal, but only in the case that Canada and Mexico agree to a quota. So far those discussions have not resulted in any actions.

Most recently, Canada’s foreign affairs minister, Chrystia Freeland, in late December said the US tariffs on steel and aluminum contradict a key component of the USMCA focused on automotive content and will therefore have to be removed before the deal is ratified by each country’s legislature.

And while Canada’s chances for securing alternative arrangements seem rather favorable, what happens with Mexico could be another story. Trump on December 21 said he would close the US border with Mexico if he does not receive funding for a wall along the US border.

“We build a wall or close the Southern border,” Trump said in a December 21 tweet. “Bring our car industry back into the US where it belongs. Go back to pre-NAFTA, before so many of our companies and jobs were so foolishly sent to Mexico. Either we build (finish) the wall or we close the border.”

While it seems unlikely that the border will actually close, there is still the chance that Trump’s fight for a wall along the US-Mexico border could further complicate reaching an agreement on the steel tariffs.

Beyond North America, the Trump administration has a number of trade negotiations lined up in 2019, most notably with the EU and Japan. In October the office of the United States Trade Representative announced the administration intends to negotiate three separate trade agreements with Japan, the EU and the UK. Trade negotiations with Japan are scheduled to begin on January 20.

Japan has repeatedly called on the US to remove the tariffs on its steel imports though it’s unclear if these trade negotiations will result in the removal of the Section 232 tariffs. When the US and South Korea reached an updated trade agreement in 2018 it included the removal of the tariffs in favor of a quota on steel imports, however in the case of Canada and Mexico, the issue of the steel tariffs remains unresolved despite reaching a broader agreement on trade.

In addition to larger trade deal discussions, Binoy Kumar, the top official in India’s steel ministry at the end of December said India and the US are also in talks regarding exemptions to the Section 232 steel tariffs, which could see India and the US come to an alternative arrangement.

Attention turns to quotas

For its part, the US steel industry has been open to quota agreements between countries, but has stressed that any action taken to remove the tariffs on steel must come with another import restriction, like a quota, in order to preserve the overall benefits of the Section 232 tariffs.

In October, Steel Dynamics Inc. CEO Mark Millett said establishing steel quotas is actually a better option on a long-term basis for US steelmakers.

“The 232 tariffs are a good stopgap, but one has to recognize we are going to have global overcapacity for some time to come,” Millett said during SDI’s third-quarter conference call with industry analysts in October. “As a country, we’re steel short — one of the few countries that is — so we need imports. Our manufacturing base needs that product and I think quotas tend to be a better way of controlling that.”

And while it remains to be seen what the outcome of all of these discussions will be, it’s a safe bet Section 232 will continue to be a dominating force in the global steel industry in 2019.

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