The LNG market continues to confound expectations. The past year saw strengthening of Platts’ JKM despite new supply, as well as de-correlation from other commodities, and flattening seasonality.
Meanwhile, in 2017/2018, large volumes of more flexible, market-priced LNG supplies reached final investment decision and were agreed for delivery. These will start to flow into the market in 2023/2024, providing an additional medium-term catalyst for the ongoing commoditization of LNG.
1. JKM decoupled from other LNG pricing indexations
In 2017 there was a relatively high correlation of global LNG and gas prices as increased supply of destination-flexible US LNG helped reduce the spread between JKM and NBP prices. JKM is the benchmark LNG spot price, reflecting LNG deliveries into northeast Asia, and JKM Derivatives are cash-settled against JKM.
But expectations of continued strong price coupling, as US LNG ramped up further, proved misguided in 2018. JKM’s correlation to typical Brent- and Henry Hub-linked LNG contracts, as well as to the NBP, fell sharply. Drivers included new US and Australian liquefaction trains suppressing JKM in the first quarter, while Brent stabilized with OPEC production discipline. Subsequently, during summer 2018, JKM rose far quicker than Brent due to proactive Chinese and South Korean pre-winter LNG buying.
JKM’s correlation with Henry Hub-linked LNG contracts was especially hampered by Henry Hub’s unexpected price surge in the last quarter of 2018, underpinned by a particularly cold winter. In addition, soaring Atlantic and Pacific LNG charter rates after the summer, as shipping journeys lengthened with US LNG deliveries into Asia, further eroded the relative competitiveness of US LNG, while JKM declined.
Legacy LNG contracts linked to either oil or Henry Hub prices face very different price drivers to LNG. This provides an incentive for counterparties to re-negotiate contracts based on non-LNG market pricing, to better reflect LNG market fundamentals.
2. JKM strengthened despite supply growth
JKM reduced its discount to the typical Brent-linked LNG contract price by almost 50%, in absolute terms, year-on-year. By contrast, the absolute premium of JKM over NBP prices grew by nearly 50% year-on-year. Whereas JKM was assessed at a discount to typical Henry Hub-linked LNG contract pricing in 2016 and 2017, this reversed last year, as JKM averaged over US$1/MMbtu above Henry Hub-linked LNG contract pricing.
3. JKM seasonality flattened
Strong growth in the seasonal Chinese gas market underpinned JKM’s particularly high 2016 and 2017 seasonality, peaking in the northern hemisphere winter.
However, in 2018 sharply declining global LNG supply in the second quarter, combined with proactive north Asian buying ahead of winter facilitated by growing Chinese LNG/gas storage capacity, reduced JKM’s seasonality. LNG production then ramped up aggressively during the November and December higher demand months, contributing to an uncharacteristic JKM decline in late 2018.
LNG marketing strategies evolve
While the LNG market in 2018 proved unpredictable, it was primarily driven by LNG-specific influences leading to JKM’s decoupling from other commodity prices. It is therefore unsurprising that LNG players are increasingly adopting physical, and derivative, pricing based on LNG benchmark to minimize cross-commodity pricing risks and undertake like-for-like hedging.
This was publicly illustrated by Tellurian’s 15-year agreement with Vitol, announced in December, for the supply of 1.5 mt/year of JKM-priced LNG. In addition, three of the four liquefaction projects, taking FID in 2017/2018, accounting for over 80% of the volumes, were underpinned by portfolio supplies, as the chart above shows.
These supplies, from Canadian and African projects, are usually marketed by a portfolio offtaker, who is free to sell the volumes at LNG market prices, with no fixed destination, when volumes ramp up. This type of flexible marketing strategy provides a further medium-term catalyst for LNG’s commoditization, increasing ensuring LNG is priced against its own fundamentals.
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As the UK’s self-imposed Brexit deadline of March 29 looms, some market participants in the container shipping industry are bracing themselves for a boost in rates.
Hopes of more clarity on the future relationship between the UK and the EU were dashed after Prime Minister Theresa May lost a vote in the House of Commons on her negotiated deal with the EU on January 15, in the greatest defeat of a sitting government in UK history.
As a result, the container shipping market is eyeing support for all-inclusive freight rates and utilization of capacity on vessels along key head-haul routes to the UK, as importers seek to stockpile goods before this date.
The market has already seen some support in recent months, with November rates bearing much of the brunt. But a last-minute jump in demand remains likely in the market.
A sideways glance at the news on a near daily basis shows the British public squirreling away essential supplies. Members of Mumsnet, an online parenting forum, have been discussing their plans to stockpile medication, toiletries, tobacco and hair dye. The BBC ran an article on January 15 on “Brexit boxes” which cost upward of £300, spanning freeze-dried food, water purification and fire starting kits.
The hoarding seen in the cupboards and kitchens of households up and down the country has a parallel in the major shipping lanes.
UK supermarket giant Tesco announced on January 16 that it will be renting refrigerated containers to increase the amount of frozen goods it can stockpile to prevent disruption stemming from Brexit, further fueling this shopping frenzy.
Some importers are looking once again to the Far East to increase imports into the UK, in case there are issues regarding customs and product gets delayed at the coast. This has potential ramifications not only for UK-EU trade, but for trade from North Asia – UK and North Asia – North Continent (any port between Gibraltar and the Baltic Sea), with freight rates to the UK likely to price as a premium over rates to the continent should there be logistical issues to encounter along this route.
The questions around ease of transit and unloading, and additional demand, comes on top of seasonal demand trends. Freight rates typically strengthen ahead of Chinese New Year, with people aiming to imports goods from China before the holiday hits and some factories close for as long as three weeks, curbing exports.
S&P Global Platts has seen the North Asia – North Continent Platts Bunker Rate 1 (PBR1) container shipping lane increase significantly since the end of 2018, with carriers desperate to move product out before the shutters come down on the Chinese infrastructure, and the Year of the Dog draws to an end.
“Will we see any movement of goods in the second half of February is the question – it all depends on how long China is off for the holidays,” said a container carrier source. With New Year celebrations sometimes extending into three weeks, it appears as if this surge in demand could be squeezed into a relatively short period of time.
Netherlands-based Samskip announced on November 11 that they would add a “Pre-Brexit Peak Volume Surcharge” to containers on their 14 weekly sailings between Amsterdam, Rotterdam and Gent, and the UK ports of Hull, Tilbury, Grangemouth and Belfast.
“As we move towards March 29 the demand for our transport services avoiding the ferry ports of southern England is increasing. Furthermore, we foresee that demand will outstrip supply before abruptly reducing in April as stock is first built up in February and March and then consumed in April before a restart at some point in late April/May,” the company said. Samskip’s surcharge will be Eur243 per load, showing just how strong they expect demand to be over this period.
Despite this, other think that the majority of stockpiling has already occurred and there is just notional amounts left to do for this year.
“Lots of pre-Brexit stockpiling for October-November, especially around Golden Week, but not now – it was always going to be tricky to stockpile in January with Chinese New Year just round the corner,” said a market participant.
Container carriers may be rubbing their hands with glee over the support this could give to the market. That prospect will be less pleasing to UK importers and potentially their customers – Mumsnet hoarders included – who are likely to shoulder the increased freight element, making future stockpiling an ever more expensive action. The old maxim appears to ring true once more: one hand giveth, the other taketh away.
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As Nigeria gears up for elections next month, policies on mining and mineral exploration will be of special interest to investors. While the country is known for its high-quality crude, with global oil prices significantly below their past highs, Nigeria is looking to attract mining investment in a bid to diversify revenues.
Currently, the oil and gas sector represents 70% of Nigeria’s GDP and 90% of its revenues. “By 2025 we want metals and mining sectors to account for 3-7% of our GDP,” the minister of state for Mines and Steel, Abubakar Bawa Bwarii told S&P Global Platts. At the moment this sector accounts for only 0.5% of Nigeria’s GDP.
For their part, investors have been eyeing opportunities in Africa’s unexplored mineral reserves, but issues around security, infrastructure, and overall ease of doing business remain key perception challenges for the continent as a whole.
At the Mines and Money conference in London in December, Hajiya Fatima Shinkafi, Executive Secretary of Nigeria’s Solid Minerals Development Fund, said: “There are perception challenges, definitely. Everyone knows Africa is the last frontier, in terms of resources, and not fully explored. For example, there’s a billion tons of coal in terms of estimated reserves and only about a million of that has been explored. In Nigeria we have some of the friendliest mining acts in Africa, but there is still some inertia.”
As part of the strategy to reform the sector, the Ministry of Solid Minerals Development has identified seven key categories for priority development: coal, bitumen, and carbonated rocks, iron ore, barites and gold. Lead and zinc, whose ore deposits are often found together, are the final priority area.
Botswana provides something of a model that Nigeria and others may try to emulate, having become a minerals investment magnet due to its reduced tax rates, and political stability. According to the 2017 Policy Perception Index from Canadian think-tank, the Fraser Institute, Botswana is the highest-ranked jurisdiction in Africa in terms of the attractiveness of its mining policies.
In a bid to attract investment and challenge negative perceptions about the ease of doing business in the country, Nigeria has put in place a digitalized licencing process and is pushing to create more mining infrastructure, such as ports and roads, to transport materials. The government is offering to mining companies a two- to three-year “tax holiday”. On top of that, investors will have duty-free imports of equipment, full ownership of their businesses and the ability to take profits out of the country.
Government-investor trust gap
Africa accounts for as much as 30% of world mineral resources, according to the African Development Bank, but they remain underexplored because of the trust gap between governments and investors.
In July 2017 Tanzanian President John Magufuli signed into law new mining bills which require the government to own at least a 16% stake in mining projects. The laws also saw royalty rates for metallic minerals such as copper, gold, silver, and PGM increase from 4% to 6%. These policies were accompanied by a series of other actions associated with Tanzanian mining that sent shockwaves through the sector. According to media reports, Magufuli’s actions were prompted by the need to ensure that the Tanzanian people benefited from mining projects in the country.
Similarly, the Democratic Republic of Congo in November classified cobalt—a key raw material in batteries for electric vehicles—as a “strategic” mineral, hiking royalties from 3.5% to 10% and aggravating the tug of war with mine investors in the country.
David Street, principal at Tembo Capital Management said: “I think one of the key issues is the mining code of particular countries. Some countries have more attractive investor legislation than others. Investors are also seeking stability in these codes – if a government is changing rules regularly it is difficult for investors to invest in that country with any degree of certainty.”
He noted that most West African countries have done well in terms of gold mining investments, following changes to their mining frameworks. Ghana, Senegal, Ivory Coast and Mali, for example, have expanded gold production significantly. Although South Africa and Zimbabwe have a long history of mining, those West African countries have grown their industries more successfully in recent years.
“Gold is usually one of the first mining sectors to grow, because the mines don’t need a lot of infrastructure to produce gold, with production relatively easy to export for sale. Coal, iron ore and base metals, for example, need a lot more infrastructure, such as good roads, railway lines and ports. And traditionally, parts of Africa haven’t had the best infrastructure compared to other parts of the world, unfortunately,” he said.
Business ethics remains a hard nut to crack in a continent that is tremendously culturally diverse. Issues still persist in community engagement and community development agreements, and often investors take a one-size-fits-all approach while working in various communities, Peter Breese, CEO of Ghana-based Asanko Gold, said during the Mines and Money conference.
“There is a misconception that bribery is the rule of law in Africa. The issue is you can’t do business in Africa until you understand what it’s like to do business in Africa; you have to understand the culture, the values and the jurisdiction that you live in. How do you integrate with the community on a local, regional and national level? When you get your head around corporate social responsibility issues is when you start to understand how to do business in Africa,” he said.
Street noted the importance of having the social licence to operate in a local community. “It’s important for example that the local people are given a fair chance of employment and benefit from skills transfer. A mine might run for 10-20 years–is there any legacy left for those people afterwards?”
Some mining companies have stepped up social responsibility by, for example, using local produce for catering at the mines, and moving towards solar power so local people could benefit from solar energy after the mine’s tenure.
How Nigeria and other neighbours in West Africa hold to recent regulatory changes in the next few years will be crucial for mining investment. The political will to drive the sector forward is not in doubt. But governments will have to achieve a balancing act between proving to investors they can offer a stable policy environment, and making sure mining development also brings long-term benefits to their own population and economy.
The post Can Africa’s mines sector shake off investors’ negative perceptions? appeared first on The Barrel Blog.
With gas production from the giant onshore Groningen field set to fall to less than 4 Bcm/year in the early 2020s and to be shut in permanently by 2030 – or even earlier – the Netherlands will become increasingly dependent on imports.
For a country used to being a net exporter of gas, the shift will be seismic.
And while the country has enough infrastructure to import gas to meet its future demand, that is not enough to secure gas supplies in the future, Annie Krist, CEO of Dutch gas trader GasTerra, said in an interview late last year.
Instead, stakeholders should think “seriously” about locking in future gas imports, Krist said.
“You need more than pipelines and other facilities to secure supplies. After all, the gas has to be bought and sold as well,” she said.
“Until now, being a net exporter of gas, the country didn’t have to worry about that. Now policy makers and other stakeholders should start thinking how to tackle this issue.”
Earlier this year, GasTerra commissioned consultancy IHS Markit to research what policies the Netherlands should follow to ensure gas supply security post-Groningen.
IHS concluded that relying fully on spot gas and LNG purchases to ensure supply security was not advisable.
This, it said, is because it would require full confidence in the reliability and liquidity of the TTF hub and also because Russia’s Gazprom is likely to shift its commercial strategy away from long-term contracts to more spot sales in the Netherlands.
“It would make sense for long-term contracts to maintain some role in Dutch gas supply for the foreseeable future,” IHS said, also pointing to the fact that Europe is in competition over LNG supplies with buyers from all over the world, particularly Asia.
Krist said the advice from IHS should be “taken seriously.”
“According to the report, if nothing changes the Netherlands will cover less than 1% of imports with bilateral long-term import contracts by the mid-2020s,” she said.
“In contrast, it is expected that other countries then will still be relying on a mix of hub trading and long-term import contracts. It seems sensible to us that we find out why.”
At present, however, GasTerra has no “concrete plans” to enter into additional import contracts, Krist said, adding that there is enough time for the Netherlands to adjust to its new reality.
“At the moment we still produce enough gas to meet demand. Our point is that the situation will change in the future. The Netherlands will become a ‘normal’ gas consuming country, just like our neighbors,” she said.
“These countries are used to importing almost all the gas they need. So we thought it made sense to inquire how and where these countries buy their gas. Preferably on the hub or primarily by means of long-term bilateral import contracts?”
Krist said that long-term contracts could be of any length, though she dismissed the likelihood of any very long-term contracts.
“Such decisions always depend on market realities. We don’t expect that the market will return to the kind of (very) long term contracts that existed before gas trade was liberalized. Today, pricing is linked to hub prices, also in bilateral contracts,” she said.
Krist also said that while there are other measures the Netherlands could take — such as cutting gas demand – the country will remain gas dependent.
“The government has already announced that it wants to lower gas demand by replacing gas with alternative sustainable energy carriers — mainly green electricity, hydrogen, biogas, etc – where that is feasible,” Krist said.
“But we should be realistic. The country still is very dependent on natural gas. No less than 40%. That means that it will probably take decades to phase out gas entirely.”
Krist said green gases also had an ever more important role to play in the future.
“Presently, our country produces approximately 300 million cu m of biogas annually. That is in energy terms roughly the same amount as what all solar panels in the country deliver,” she said.
“We think that potentially 3 Bcm of biogas could be produced in 2030. Also the prospects of hydrogen as fuel and as an alternative power storage solution look pretty good.”
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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.
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.
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.
The post As IMO 2020 lures newcomers to bunker sector, profit is far from guaranteed: Fuel for Thought appeared first on The Barrel Blog.
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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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.
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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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.
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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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.
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.
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.
The post Insight from Shanghai: Waking up from the Chinese dream appeared first on The Barrel Blog.
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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