Insight: Extreme volatility returns to NYMEX natural gas futures

With volatility making a return to the previously calm US natural gas futures market, it’s important to remember that price swings happen in both directions, as individual fundamentals wax and wane in terms of their influence.

November saw notable price volatility in the December Henry Hub prompt-month contract. The December contract settled and expired at $4.715/MMBtu, up $1.53/MMBtu from the November NYMEX settle.

The onset of a cold November with the looming potential for a cold winter, combined with natural gas storage concerns, created a volatile whipsaw of price movements and resulted in the highest settlement for the NYMEX prompt-month contract since 2014.

November’s bullish market developed in spite of rising domestic production, with the Energy Information Agency estimating dry gas output will average 83.2 Bcf/d in 2018, up 8.5 Bcf/d from the previous year. It is precisely this abundance of supply that appears to have encouraged gas utilities to rely more heavily on volumes sourced directly from pipelines, rather than injecting into and then later pulling from gas storage.

US temperatures in November were the coldest for the month going back to 2014, averaging 46.2 degrees Fahrenheit. This in itself was enough to spook gas markets.

Additionally, the US went into winter with gas stocks around 17% lower year on year. Storage concerns raised during the summer injection season continued as the EIA announced the first withdrawal of the season. This amounted to a whopping 134 Bcf drop in the weekly change of US inventories – the largest initial withdrawal in the past eight years and more than double the previous record  pull of 53 Bcf in November 2015.

For prompt-month NYMEX, the November 14 settlement at $4.837/MMBtu was the highest price since February 26, 2014.

Henry Hub natural gas prompt price soars in November

The arrival of volatility and higher prices now means the market is looking towards new developing fundamentals and weather trends. As the December prompt month rolls off into January, the market will test higher resistance and lower support levels at these $5/MMBtu and $4/MMBtu thresholds.

With recent price gains in November as large as 73.6 cents in a single day, or single-day losses as big as 79.9 cents, participants must not forget how fast the prompt-month contract blew through the $4/MMBtu threshold on the way up. Prices can fall just as quickly.

The 12-month strip shows how much changed from the start of November. Despite the dramatic price increase in winter contracts, further down the curve, as markets enter summer injection season, the balance of the 12-month strip did not change much with all April – October contracts settling in a range of $2.746/MMBtu to $2.894/MMBtu, at the November 29 close.

Henry Hub natural gas future curves at start and end of November 2018

It is during this summer period that production will dominate from a fundamentals perspective as the burgeoning supply looks for new outlets of demand, such as power burn and exports.

Ultimately, winter weather will drive it from here. A mild winter will test the $4/MMBtu support level, and cold weather could push it above $5/MMBtu.

With gas production records expected to continue, weekly reports of natural gas storage levels will have less influence in the market. Other fundamentals – such as weather, pipeline and LNG exports, and power generation demand – will be more in play.

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Insight: Brazil steel touts Bolsonaro despite controversy

The Brazilian steel, metals and mining sectors expect an upturn in investments in the country in second-half 2019 following inauguration of a new government which aims to end a period of institutionalized corruption.

Representatives of industry associations and the mining sector talked up the prospects of economic recovery under incoming president Jair Bolsonaro last week in Rio de Janeiro, but bumps in the road may remain, from a tricky trade relationship with China to the high cost of financing.

“A new economic cycle is now beginning,” said Marino Garofani, president of the Brazilian association of metallic construction, ABCEM. “The new government has a new posture of compliance.”

The ABCEM president nonetheless notes that while an economic upturn is widely expected, it is still too early to see “concrete plans” that would actually guarantee this.

President-elect Jair Bolsonaro of the Social Liberal Party, known for his support of national conservatism and sometimes compared to US President Donald Trump, is due to take office January 1. In spite of the former army captain’s sometimes controversial views on women, gays and the environment, Brazil’s business community in the main applauds his pro-market policies and his attempts to break with recent corrupt practices in Brazil.

This has already been signaled, according to Marco Polo de Mello Lopes, executive president of Brazilian steelmakers’ association IABr, by the president-elect’s current cabinet appointments, which are not linked to political parties as has typically been the case in Brazil’s recent political history.

S&P Global Platts Capitol Crude podcast, hosted by Meghan Gordon and Brian Scheid

More on the Bolsonaro effect: Capitol Crude  examines the impact on Brazilian oil

Brazil’s Bovespa stock exchange has gained around 10,000 points since it became clear Bolsonaro would be elected. “In principle financial prospects have improved… he has passed a better message to the market,” said Jose Carlos Martins, CEO of Neelix Consulting, active in the mining sector. This is widely seen as an indication that capital, including foreign funds, may be eyeing a return to invest in the country that was struck by a deep 2014-2016 recession, worsened by the gigantic “Car Wash” scandal, involving major companies including Petrobras and construction companies such as Odebrecht and Camargo Correa.

Bolsonaro has apparently committed to kick-starting the Brazilian economy – expected to grow 1.5% this year after edging into recovery last year from the three-year recession – by signaling investments in the construction and infrastructure sectors as a priority. This means more spending on roads, urban transport, ports, airports, oil and mining: according to IABr’s Mello Lopes, 3,300 construction projects in the Brazilian private sector alone have ground to a halt since the recession took hold. Negotiations are now taking place between industry associations and representatives of the new government in an attempt to restart some of these projects, including via the “public-private partnership” system of undertaking some major works, and do away with the so-called “pen blackout” – a freeze on signing projects, the steel industry executive said.

Activity levels in Brazil’s construction industry, a key driver of economic growth, have declined 50% since 2014, according to ABCEM’s Garofani. In terms of tonnage, 700,000 mt of steel is expected to be used this year in Brazil’s construction industry, a level similar to 2017, but just half the usage levels in 2014.

“This is likely to grow to 900,000 mt in 2019, all Brazilian steel. Investment in Brazil’s construction sector may grow 10% in 2019, from a low base, but it’s hard to see more than one year ahead,” Garofani said.

Garofani and Mello Lopes however indicate that the cost of financing within Brazil is still prohibitively high: interest rates continue higher than in many countries meaning that an influx of international investment will be essential to get the construction industry – a vital creator of jobs – on its feet again.

One spanner in the works is the perception that Bolsonaro is not keen on accepting Chinese investment capital, for political reasons. This is despite the fact that due partially to US protectionism, China in recent years has become Brazil’s biggest trade partner, an avid consumer of Brazilian iron ore, soybeans, meat and corn, as well as a supplier of cheap steel. Brazil has so far chosen not to impose anti-dumping measures on the bulk of its Chinese steel imports because maintaining a firm trade relationship with the Asian giant was considered by the former Workers Party government to be in the public interest, according to IABr.

Brazil is the world’s ninth biggest steel producer and tenth biggest exporter of steel. With the country’s steel sector currently working at just 68% of its productive capacity of around 50 million mt/year, eyes will be on the new government to see if its stance on steel imports hardens. “We could reach a steel capacity working rate of 75% if the economy recovers,” Mello Lopes said.

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Fuel for Thought: Carbon capture projects gaining traction

US upstream company Occidental Petroleum is committed to carbon capture and injection as a method of boosting oil recovery both in its Permian shale operations and outside the US, CEO Vicki Hollub said last week.

She was one of a number of industry leaders who outlined carbon capture projects around the world, many geared to utilizing CO2 from heavy industry in Europe and the US, at the Accelerating CCUS conference in Edinburgh.

In the US, carbon capture got a boost this year from new tax credit legislation known as 45Q.

Hollub said Oxy, as the largest “handler” of CO2 for enhanced oil recovery, was achieving recovery rates of as much as 70% at one of its conventional Permian reservoirs due to carbon injection, and aimed to extend CO2 injection to its Permian shale operations, following encouraging results from four pilot wells.

With Permian producers typically only recovering 6%-12% of “in-place” hydrocarbons, carbon injection is likely to become widespread in the shale industry, and there are growing prospects for bringing piped carbon dioxide from industries in the central US to the Permian, Hollub said.

“What we want to do is use enhanced recovery also in the shale play. We do know we can get incremental hydrocarbons out of the shale play with CO2 injection,” Hollub said. “We think CO2 is an opportunity. We have a strategy to capture CO2 from multiple industrial sites in the middle part of the US and to get that to the Permian by pipeline.”

Oxy is also looking at deploying CO2 reinjection at three production blocks it recently obtained in Oman, sourcing the CO2 from the electric power generation process needed for operations there, partly due to a recent investment in power company NET Power. It will also look at extracting CO2 directly from the air at the same project, she said.

She outlined similar possibilities in Colombia, at Oxy’s La Cira-Infantas joint venture, and at the Al Hosn ultra-sour gas processing plant in Abu Dhabi, where the CO2 could be re-injected into nearby reservoirs.

“We’re looking at a lot of things. Everywhere we look at there’s the potential to do this,” Hollub said.

European carbon capture drive

At the same event, the Norwegian energy ministry’s director general for climate, industry and technology, Bjorn Haugstad, said Norway’s carbon reinjection continued to expand, having started 23 years ago with injection at the Sleipner field, then the Snohvit gas field in the Barents Sea, and most recently Gudrun.

Partly because of the tax incentives involved, Sleipner had been closely monitored and no CO2 leakage detected, he said.

By late 2020, Norway aims to approve plans to bring CO2 by ship from one or two industrial facilities, cement manufacturer Norcem and waste processor Fortum, for reinjection into depleted North Sea fields, in which Shell and state-controlled Equinor are expected to play a role. The cement industry globally accounts for 2-3% of all CO2 emissions, according to Norcem.

The plans could include injecting CO2 shipped from other countries including Sweden, which has emissions associated with steel production, as well as Swedish refiner Preem, Haugstad said.

“Three Norwegian fields are doing CO2 injection on an absolutely routine basis and the experience so far is it’s completely safe,” he told S&P Global Platts.

Earlier, Claire Perry, UK energy and clean growth minister, reiterated UK efforts to develop carbon capture, utilization and storage projects based around industrial clusters, rather than solely on individual power stations.

She noted that a longtime planning scenario produced by Shell in which global temperature increases are kept to less than 2 degrees Celsius entails construction of 10,000 large-scale carbon capture and storage projects by 2070.

Currently, the world has around 20 large-scale CCUS facilities.

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Insight: Lithium-ion batteries enter the fast lane

Both the transportation and power industry have been facing significant changes, driven by a combination of policy and technological factors, and S&P Global Platts Analytics sees lithium-ion batteries playing an instrumental role in these transformations.

When it comes to batteries, there have been and will continue to be synergies of power storage and transport sector battery technology. In the power sector, large deployments of wind and solar photovoltaics will increase the need for storage to manage their intermittency. Recently, the US has seen several RFPs in which developers have bid projects combining solar PV assets and lithium-ion batteries – a trend discussed recently in S&P Global Platts Analytics’ U.S. Power Storage Outlook.

Because of the often-siloed nature of the energy sector, there is a need for some perspective regarding the relative size and importance of the sectors. The fact is that energy sector applications of batteries are and will continue to be dominated by uptake in the transport sector.

Intuitively, this should not be surprising, as batteries provide for the full energy transport needs of an electric vehicle, but they only play a supporting role to other generating sources in the power sector. Globally, there is currently only 2−4 GWh of lithium battery storage installed in the power sector, according to the International Energy Agency, whereas batteries in electric vehicles account for 140 GWh.

The right-hand side of the chart above gives a sense of the relative size of battery demand under some strong battery storage penetration scenarios. On the transport side, assuming 25% of light-duty vehicles in the US were EVs (with a 60 kWh battery) this would imply 3,100 GWh of battery needs. On the power side, assuming 25% of all US households installed home batteries (sized at 13.5 kWh), the total need would be <500 GWh. This is about the same level of battery needs under a scenario in which 25% of US natural gas fired peaking generation plants are replaced with a combination of solar and storage. As can be seen, the potential on the power side is clearly much smaller in scale – and the power sector can also choose from a wider range of non-lithium ion alternatives.

The role of transport

The electrification of the transport sector is seen as a potential solution to reduce local air pollution and potentially also greenhouse gas emissions (depending on factors such as the carbon intensity of the power sector). Developments in battery technology have been critical to this. Research on lithium-ion batteries began in the 1970s.

In 1991, Sony commercialized the first lithium-ion battery to increase the battery capacity of its video recording devices. However, it took much longer for the transport sector to adopt lithium-ion batteries, despite its ability to store much more electricity by unit of weight or volume than older technologies. Early EV designs from the 1960s relied mostly on nickel-cadmium batteries. And for a while, lithium-ion batteries were too expensive to be used in transportation applications while nickel-cadmium (NiCd) or nickel-metal hydride (NiMH) batteries were too heavy to provide EVs with adequate ranges. In contrast, electric hybrid vehicles needed less battery capacity and were able to utilize the relatively inexpensive NiMH batteries. The earliest Toyota Prius hybrid had a battery capacity of less than 1 kWh, while the Tesla Model 3 houses a 75 kWh battery.

While EV sales are increasing, they remain a small fraction of new car sales and the total vehicle fleet. EVs will account for 2.5% of total 2018 passenger vehicle sales, according to the latest S&P Global Platts Analytics Electric Vehicle Sales & Policy Scorecard.

Cost will be a key determinant of further uptake. The purchase price of EVs is expected to remain higher than that of gasoline or diesel vehicles, largely due to the high cost of batteries. S&P Global Platts Analytics modelling indicates that savings in the costs of fuel and maintenance will not be sufficient to make EVs competitive on a total-cost-of-ownership basis for a while. However, we do expect further EV cost reductions and technology improvements over time. We estimate that passenger EV sales will continue to accelerate, reaching 24 million in annual sales in 2030.

This fast ramp-up of EV sales will significantly raise demand for raw materials such as lithium, cobalt, manganese and nickel. Development of new mines and intermediate conversion and processing plants takes time, raising concerns that supply will not be able to keep up with demand, and that shortages will raise battery prices and slow down the price competitiveness and uptake of EVs.

Material world

Materials currently account for nearly 50% of the total battery cost, among which cobalt, lithium, nickel and graphite are the most expensive, accounting for 30% of total cost. Process and chemistry improvements and pack engineering advances will lower battery prices, all else being equal. In turn, the battery cost exposure to metal price risks will increase as these key raw materials account for a larger share of the battery price.

How this ramp-up in demand for metals plays out will depend in part on developments in battery chemistries. The industry has developed a wide range of lithium-ion battery types, varying in capacity, chemistries and performance. There is no commercially available ideal lithium-ion chemistry suitable for all applications. The choice of chemistry is typically a trade-off between energy density, power density, safety, life and cost requirements, and the metal needs vary.

Energy density is critical for the electrification of transportation. Within the industry, the concept of “range anxiety” has been widely discussed as one of the factors limiting customers’ interest for EVs. Increasing battery capacity is the primary option for increasing vehicle range. However, as there is a limit to how much battery capacity can be installed due to vehicle space and weight limits, high energy density is key to achieving long-range EVs.

In addition, the feasibility of heavy-duty vehicle electrification will partly depend on future increases in energy density. Electrifying long-range heavy-duty trucks with current lithium-ion batteries would shrink the amount of goods trucks can transport over long distances.

However, energy-dense chemistries are also the ones that use expensive raw materials, such as cobalt. While some early EVs sold outside China relied on low-energy density batteries – for instance, the first Nissan Leaf used the cobalt-free lithium-ion manganese oxide (LMO) chemistry – automakers use high energy density batteries in their latest EV models to achieve higher vehicle ranges. Tesla has been the main proponent of the lithium nickel aluminum cobalt oxide cathode (NCA). Other manufacturers use the lithium nickel manganese cobalt oxide (NMC) chemistry.

Since 2016, prices for cobalt traded on the London Metal Exchange more than quadrupled to reach a peak of $95,500/mt in March 2018. Similarly, the price of lithium carbonate more than doubled since 2016, but has been decreasing recently. Since the launch of S&P Global Platts battery-grade lithium carbonate assessment on May 4, the seaborne price has fallen significantly from its opening assessment of $18,000/mt.

Longer range EVs use the NMC and NCA chemistries, which favour the use of lithium hydroxide instead of lithium carbonate. Despite the growing demand, prices for lithium hydroxide have been dropping recently, highlighting ample lithium supply. Indeed, concerns over lithium supply have shifted towards concerns about lithium conversion capacity, which is needed to upgrade raw material to the carbonate and hydroxide needed in batteries.

Lithium spodumene and brine volumes continue to come to the market in ever-increasing numbers from Australia, Chile, Argentina, Bolivia and China. While Chinese brine and spodumene is largely seen as lower quality it can be upgraded to battery-grade quality. Weakening S&P Global Platts battery-grade lithium carbonate assessments for the seaborne as well as Chinese domestic market suggest easing concerns over near-term supply, with all four assessments down from where they were assessed when first launched.

Ensuring a steady supply

Automakers have tried, with varying success, to lock-in raw material supply of cobalt and lithium. Earlier this year, Gangfeng signed a deal with LG Chem to supply lithium for the period 2019−2025 and signed a contract with Tesla for a two-year supply, with an option for three additional years. However, Volkswagen failed last year to secure long-term cobalt supply after asking for 10-year contracts. Cobalt also faces a concentration risk, as most of the production and reserves are located in the Democratic Republic of Congo. On the contrary, lithium reserves are more widely spread, but Chile and Australia account for almost 80% of 2017 production.

It is important to note that there is currently no real alternative to lithium for the batteries used in the transport sector. While the battery industry is using different forms of lithium − lithium carbonate or lithium hydroxide − the need for lithium is relatively comparable among all the different lithium-ion battery chemistries. Finding a good replacement would not be an easy task for the industry. By 2025, S&P Global Platts Analytics expects a 10-fold increase in lithium demand from passenger EVs.

Technology development will be instrumental in reducing cobalt exposure. Battery manufacturers are partly replacing cobalt with nickel in new batteries to reduce cobalt needs and increase energy density. The battery of the first BMW i3 used the NMC 3:3:3 chemistry (with three parts nickel, three parts cobalt and three parts manganese). A doubling of cobalt prices would lead to a 13% increase in battery cost for this chemistry. However, the industry is moving towards the NMC 6:2:2 (with six parts nickel, two parts cobalt and two parts manganese). This would cut the cobalt need, limiting the battery price increase to 8% if cobalt prices double.

Research is ongoing to further reduce cobalt content in batteries, and possibly even to eliminate it. The industry expects the commercialization of the NMC 8:1:1 within the next few years, though safety concerns due to lower cobalt content may delay this.

While several companies are working on cobalt-free chemistries, technology advances generally take a long time in the battery space, as time is measured in decades. Cobalt provides stability to lithium-ion batteries and is difficult to remove completely while keeping high energy density. New technologies, such as solid-state batteries, may decrease the need for cobalt, but are still many years away from mass commercialization. New cobalt supply will still be needed in the interim, as the scale of the expected growth in EVs will outpace such technological developments.

Finally, battery recycling will become a critical topic, as EVs reach new segments and take up an increasing share of new vehicle sales. It is likely that governments will play a key role in supporting recycling driven by waste and sustainability concerns, as well as the risk of raw material scarcity. Automotive manufacturers typically guarantee batteries for 100,000 miles or eight years, but batteries’ capacity degrades with use and they ultimately need to be replaced. There are increasing discussions about the second use of batteries, with some OEMs investigating the reuse of EV batteries for power storage applications.

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Thank you for visiting – Gracias por visitarnos Potenciar Educacion Superior …


In the LOOP: US Gulf Coast crude exports to Venezuela resume

Two rare cargoes of US Gulf Coast crude could be making their way to Venezuela, according to S&P Global Platts fixtures reports.

Last week, Vitol was heard to have booked two Panamax-sized vessels to move crude from the USGC to Venezuela. Panamax vessels can carry roughly 500,000-800,000 barrels of crude oil. One of those vessels, the SCF Pacifica, was loaded in Houston over the weekend.

The other vessel reported, Skopelos, was also to be loaded November 25. However, that vessel was spotted off the coast of West Africa on Monday, according to Platts cFlow trade flow software.

The US has exported about 1 million barrels of crude to Venezuela during the past six weeks, according to S&P Global Platts Analytics and cFlow. None was transported during the weeks ending November 9 and November 16. For the weeks ending October 26 and November 2, the US sent 522,000 barrels and 534,000 barrels to Venezuela. No other US crude exports to Venezuela have occurred since 2003, according to US census data.

Crude being transported to Venezuela is likely WTI MEH, Light Louisiana Sweet or Domestic Light Sweet, a barrel blended to match the specifications of WTI Midland, according to market sources. The exported light sweet barrels could be sent for processing at the Isla refinery on the island of Curacao. PDVSA’s national refining system has an overall capacity of 1.6 million b/d through five refineries: 645,000 b/d Amuay; 310,000 b/d Cardon; 187,000 b/d Puerto La Cruz; 140,000 b/d El Palito; 335,000 b/d Isla, and the 16,000 b/d Bajo Grande asphalt plant.

As much as 104,000 b/d of foreign light sweet crude could be directed to complete throughput at the Isla refinery, according to a production plan from Venezuela’s state-owned PDVSA seen by S&P Global Platts. The light sweet crude would be run with Venezuelan heavy sour at the refinery. However, PDVSA was heard to have cut off crude supply to the refinery since May, when the US-based ConocoPhillips first tried to seize PDVSA assets in the Caribbean in connection with a debt dispute between the two companies. Light sweet US crude can also be blended with heavy sour Venezuelan crude, with the higher API gravity crude then sold as a blend in export markets for a higher price.

According to market sources, PDVSA could use the Isla refinery’s production to meet payment commitments to debts owed to Russian and Chinese companies. The front-month spread between LLS and WTI MEH reached a three-month high November 20 of $2.15/b, before narrowing 45 cents/b to $1.70 November 21 and a further 85 cents/b to end Monday at 85 cents/b. As LLS’ premium narrows, the grade becomes more competitive with WTI MEH for export to markets in Latin America. Since the start of November, LLS’ premium to WTI MEH has fallen 95 cents/b.

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Insight: EU carbon market stages comeback in 2018

The carbon market in Europe made a big comeback in 2018 after years of stagnation, with prices of European Union allowances more than quadrupling to above €20/mt ($23/mt) after lawmakers overhauled the system’s rules for the period after 2020.

Higher carbon prices are likely to boost the profitability of companies operating nuclear, wind, solar and hydro-electric power plants, driving further growth in renewable energy capacity in Europe. They also signal a long-term drop in the use of the most emissions-intensive fuels for power generation, hard coal and lignite, and provide a stimulus for innovation in low-carbon industrial goods and processes.

After years of being flooded with surplus carbon allowances, sharp supply cuts starting in 2019 look set to reposition the EU Emissions Trading System as the principal tool to decarbonise Europe’s economy over the long term.

The overhaul of Europe’s carbon market not only tilts the economics of electricity generation away from fossil fuels and towards cleaner power, but it also puts wind in the sails of carbon markets in general. That sends a clear message to other regions grappling with the same pervasive energy trilemma: making energy secure, sustainable and affordable.

The road to 2019

The road to 2019 has not been an easy one. The very idea of carbon markets came close to redundancy along the way, as low prices persuaded some EU member states to go it alone on carbon pricing policies.

From a pre-financial crisis high of over €30/mt in 2008, carbon prices crashed during the downturn that followed. That’s because the supply of carbon allowances was fixed under the scheme, while demand was linked to actual CO2 emissions, which fell as demand for electricity and CO2-intensive products collapsed. Carbon prices dipped to as low as €3/mt in 2013 in the wake of a second economic slowdown in Europe, threatening to make the ETS irrelevant as a driver of decarbonization.

EU carbon price recovery

This problem of excessively low carbon prices was not just the result of global economic conditions. It was further compounded by overlapping EU energy and climate policies, including targets for increasing renewable energy and energy efficiency for 2020 and 2030. Far from pulling in the same direction, some of these energy and environmental policies directly undermined the price signal produced by the ETS.

Under a cap-and-trade system, CO2 emissions fall as a result of a declining annual carbon cap, not as a function of the carbon price. In a free market for rights to emit CO2, the environmental benefit is delivered through the cap, with the price determined by market forces. Still, for the European carbon market to send meaningful investment signals, a better balance was needed between supply and demand.

Major interventions

A series of major market interventions followed as Europe’s lawmakers tried to avoid a complete collapse of the system. Early examples of this included “back-loading,” a move to postpone the release of 900 million EUAs in government auctions from 2014 to 2016. While this measure avoided carbon prices falling to zero, it only addressed a symptom, not the underlying problem: prices are vulnerable in a market in which supply cannot react to demand.

Brussels authorities understood that to make the ETS future-proof, ad-hoc supply-side interventions would not be enough – the market needed a mechanism that would make it resilient to future demand shocks by controlling supply automatically.

Cue the second major intervention: the Market Stability Reserve. The MSR is a mechanism to withhold surplus EUAs from the market, reducing any current or future oversupply. The MSR was agreed by the EU’s co-legislature in 2015 and strengthened under legislation passed in 2017. It is set to curb the volume of EUAs in circulation, which represents 1.655 billion mt of CO2 equivalent, by 24% per year starting in January 2019. Going forward, the MSR is expected to react to any factor that might increase the volume of carbon allowances in circulation by withholding a fixed proportion – 24% of the surplus – from government auctions in the following 1−2 years.

The MSR’s expected impact on supply has led some analysts to forecast a supply crunch in 2019−2022, as net supply in the market falls below the volume needed for power generators to hedge forward power sales, forcing CO2 abatement. Anticipating this cut to supply, buyers increased their activity in 2018, while sellers had little reason to offload volume. This pushed carbon prices to well above €20/mt by August, and the gains were further compounded as the looming supply cuts attracted financial players back into the market following a long absence.

In addition to the MSR, EU lawmakers agreed on other changes for the period 2021−2030, including a steeper 2.2% reduction in the annual carbon cap, as well as other rule changes including more targeted free allocations for companies in trade-exposed sectors. The EU’s carbon market legislation also includes provisions that allow for a future review, opening the way for further intervention to ensure the market functions as intended.

Looking ahead

What does the future hold for the European carbon market? In the power sector, it has widely been assumed that coal-to-gas switching would arise as a result of higher carbon prices – but as 2018 demonstrated, this hasn’t always been the case.

Coal-to-gas switching has not been happening so far in 2018, quite the opposite. European gas prices were high in late 2018 due to volumes going into storage ahead of winter, declining Dutch production and strong Asian markets for LNG. Those high gas prices squeezed profit margins on gas-fired power plants, helping keep emissions-intensive coal-fired plants ahead of gas-fired units in the merit order for power generation.

In effect, instead of coal-to-gas fuel switching, the European power market has been experiencing coal-to-renewables switching. Wind power is increasingly pushing coal plants off the grid on windy days, while coal plants come back onto the grid on cold, still, winter days when heating demand is high and wind fails to materialise.

This trend is likely to become more pronounced as solar and wind capacity increase across Europe, with weather playing a larger role in pushing older coal and gas units out of the money.

In general, higher carbon prices have several implications: expect to see renewable energy taking a bigger slice of the electricity market in Europe; higher wholesale power prices; a long-term drop in the use of hard coal and lignite for power generation; greater innovation in low-carbon industrial processes; and increased investment in energy storage and energy efficiency.

While the MSR will tighten the supply side of the carbon market, demand-side factors could yet weigh on carbon prices and keep any severe price increases in check.

“The MSR itself does not raise EUA prices, but it makes the market shorter,” said Jeff Berman, director of emissions and clean energy at S&P Global Platts Analytics. “This should lead to higher EUA prices, but if emissions reduction costs fall, then EUA prices could also remain low,” he said.

On the demand side, Germany – the largest power market in Europe – has appointed a commission to work on ways to move away from coal and lignite. This is expected to result in a managed closure process for its most CO2-intensive power plants.

However, Germany cannot achieve this goal quickly. The country is already phasing out low-carbon nuclear power for other environmental and safety reasons. This means any move away from coal must happen on a gradual timeline, allowing renewable energy to fill the gap left by nuclear, keeping coal in the mix for several years to come. Other downside factors include a potential fall in natural gas prices, which could allow coal-to-gas fuel switching to happen at a lower carbon price, thereby cutting CO2 emissions and demand for allowances.

There are also other potential challenges for the carbon market in the wider international context: if other countries outside Europe fail to press ahead with ambitious climate policies, high carbon costs in Europe could become problematic for the EU to sustain. Clever diplomacy and careful rule-making may be required to avoid European businesses facing undue competitive distortions.

But could the carbon market again suffer a major price crash – for example, if another economic crisis occurred? That’s unlikely. When drafting the MSR legislation in 2017, EU lawmakers designed the reserve to react automatically to quantitative demand-side fundamentals. In effect, the MSR future-proofs Europe’s carbon market by controlling the volume of allowances available to regulated companies. This makes it very unlikely that a future carbon price crash could occur, and is a key reason why banks and other financial players become confident enough to move back into the market on the buy-side in 2018.

That the carbon market has survived political opposition among some industries and EU member states, as well the global financial crisis, is remarkable. But it is also testament to the resilience of the core idea: Europe wants to build a low-carbon economy by the second half of this century without breaking the bank. This long-term effort needs coordinated policies that can deliver emissions reductions at the lowest cost. It also requires long-term price signals that have the power to shift capital investment on to a sustainable track at scale. Overcoming the tension between those two goals has been a fundamental issue for the EU carbon market since it became operational in 2005.

After years of oversupply and prices that were too low to be meaningful, the carbon market has now been strengthened and positioned to play a key role in achieving the EU’s goals. The direction of travel is clear.

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Exit the Dragon? New port restrictions to limit Chinese met coal imports

China’s National Development and Reform Commission (NDRC) has imposed further port restrictions on both metallurgical and thermal coal, effective from 14th November.

There was no official announcement, but traders and steel mills have told Platts the NDRC verbally informed the General Administration of Customs that any imported coal would no longer be able to clear customs until the end of 2018.

This means the volume of imported coal will likely be halted through the end of year, across all Chinese ports including the main northern ports of Caofeidian, Jingtang and Bayuquan. Those end-users who have outstanding import quotas for 2018, however, may report to the authority for review and approval, case-by-case.

Port-related restrictions have been frequently imposed by the Chinese government this year. In April, users of southern ports were notified they would no longer be able to receive any imported coal. In July, northern ports such as Jingtang had transport restrictions imposed, with diesel-fueled trucks banned as an environmental measure.

Import target

Similar to many other commodities, government control of imports typically aims to support domestic producers and in this case, domestic coal prices, by ensuring the total import volume does not exceed the previous year’s.

According to customs data, China imported 271 million mt of coal in 2017, including both thermal and met coals, at a monthly average of 22.6 million mt. This year 202.6 million mt were imported through September, a monthly average of 22.5 million mt. Met coal accounted for just 25.8% of the total imported coal in 2017.

However, the total volume of met coal imported into China this year through September saw a steeper decline, dropping 6.2% compared with the same period of 2017. The above chart shows China has imported 50 million mt of met coal through September 2018, compared with 53 million mt reported for the same period of 2017.

Despite the lower met coal arrivals for this year, the commodity has been included in the port restriction policy. This could be due to the relatively large share of thermal coal in the mix, accounting for 75% of total Chinese coal imports in 2017.

Dip expected in Q4

A possible implication of the port restrictions through 2018 could be a sharp fall of the met coal import volume during the last quarter. This is also suggested by the Platts spot trade data.

Platts spot trade data for met coal is a leading indicator to the Chinese official reporting, on a two month-ahead basis. This is because the deals observed typically require a two-month lead time for the physical cargo to arrive at Chinese ports.

For the first 9 months of 2018, Platts observed 16.4 million mt equivalent of met coal trade to China, 33% of China custom’s total reporting of 50 million mt. Based on this data, Platts’ observation of 1.8 million mt of spot trade for October would suggest December arrivals reaching around 5.5 million mt, but whether or not this volume will be customs-cleared and reach end users is now in question.

Platts observed spot trade data going back to January 2016 demonstrates a generally positive correlation with that of the official China custom reporting. The correlation between Platts’ data and China customs reporting were consistently positive near 60%. Although not perfect for forecasting, the Platts spot trade data makes it statistically possible for the market to stay ahead of the curve, to gauge a forward trend by approximately two months.

Two-tier market ahead?

With China’s temporary withdrawal from trade flows now likely, a two-tier market for met coal could emerge, with domestic prices potentially strengthening to outpace international values.

Platts last assessed Chinese imports near parity levels of $223/mt, but the port restrictions could potentially increase the spread.

This situation could be short-lived – in the absence of official announcements, the market is expecting China to re-open to the international market as early as January 2019.

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