Natural gas importers across the globe are looking at the next few months with similar anticipation as fans of the next season of Game of Thrones. In both cases, winter is coming.
The prospects of a natural gas glut, which was commonly heard within the energy industry not that long ago, has vanished following last winter’s tight market, and is being replaced by concerns over security of supply.
One of the most striking signs of this concern has been the race to fill storages in recent month. Underground gas storage is one of the most efficient tools to mitigate seasonal demand fluctuations, and it was widely used last winter to compensate for the impacts of late cold spells on both sides of the Atlantic. As a result, storage inventories fell to a four-year low level in the United States by the end of last winter and reached record lows in Europe.
This situation prompted strong injections to replenish underground storages, and contributed to sustained levels of imports in Europe and high prices throughout this summer. Still, despite these efforts, inventory levels as of the end of September were slightly lower than last year’s levels in Europe, and almost 20% lower in the United States.
Enter the dragon
But there is more to this story. Just like last season’s cliffhanger, winter is also bringing along new major player in the natural gas game. China, for one, which experienced an unprecedented 14.5% growth of its natural gas consumption in 2017, supported by continuous economic growth and by a strong government push towards a cleaner energy mix. The high level of air pollution in urban areas triggered strong policy measures to “win the battle for blue skies.” This included massive conversion from coal-to-gas for small industrial and residential boilers. The resulting gas demand surge could not be met by higher domestic production or import capacity, or even short-term liquefied natural gas (LNG) imports. As a result, China experienced supply shortfalls over the winter.
There were multiple lessons from this episode. Beyond the immediate emergency measures to handle the shortfall, they triggered a wide range of investment decisions and policy measures since the beginning of this year to reinforce the country’s security of supply – further development and diversification of the gas supply portfolio, new investment in storage, pipeline and regasification capacity, as well as new policy guidelines and targets for natural gas development.
At the same time, China’s natural gas demand keeps growing. During the first half of 2018, China’s gas consumption increased by 17% year-on-year, while LNG imports, a growing source of supply for the country, grew by 45% year-on-year for the January to September period. Domestic production and import infrastructure development have also grown but they still struggle to keep pace, and some local stakeholders brace themselves for the eventuality of a second tight winter.
The strong increase in China’s LNG spot procurement in 2018 contributed to higher market prices in Asia, which stood at above $10/MMBtu throughout the summer, a level that was reached last year only during the coldest winter months. Asian high prices, combined with strong storage injection activity, also contributed to a continuous rise in European gas prices since the beginning of summer.
Across the narrow sea
Another point of recent concern is the availability of LNG tankers. Once seen as a purely logistical aspect in supply contracts, LNG vessels have become a central component of the emerging short-term LNG trade. Ship availability was not a concern less than two years ago, when the spot chartering price was around $30,000 per day and shipyards were struggling to find new orders to maintain activity. But this has changed today, with prices rising steadily over the past months and reaching $140,000 a day (as of October 23) and with the risk of more tension when temperatures drop.
This is almost as high as the all-time record ($150,000) experienced during the winter following the Fukushima nuclear incident of March 2011, when Japan had to procure LNG to compensate for its offline nuclear power generation capacity.
Of course, risk exposure is not the same for all markets. Mature markets in Asia, Europe or North America have storage, diversified power generation assets, demand response measures and other mitigation tools at their disposal – plus they are more likely to endure higher prices than buyers from emerging markets. At the same time, the LNG short-term supply pool, for which Japan, Korea and Europe used to be the sole buyers, has now to be shared with a growing number of buyers.
The night is dark and full of terrors … or is it?
In the end, for gas markets as for television series, the outcome is never certain and some twists and surprises are likely to happen along the way. For winter gas demand needs, it boils down to remembering that weather is highly unpredictable. This may seem obvious, and yet out-of-the-norm winters tend to have lasting impacts on market behaviour.
If the coming winter happens to be a mild one, market prices are likely to remain stable or even decrease in the most extreme cases. A side effect could be that gas in stock would not be used as expected; market operators who booked and paid for storage capacities would tend to see them as useless costs. Finally, the overall market sentiment could probably end up considering security of supply as not so necessary – until the next tight market episode. For it can also happen to be the other way around, with risks of strong price volatility, (much) higher market prices and, in the worst-case scenario, some physical supply issues such as last winter in China.
Highlighting the importance of security of supply issues and their potential consequences is not about fearmongering, of course. It is about raising awareness of market stakeholders and policy makers and underscore that once-in-a-lifetime weather or security events do happen – sometimes more than once.
Are aviation biofuels ready for take off?
Air travel is booming, with the number of air passengers set to double over the next twenty years. Aviation demand is particularly evident in in the Asia Pacific region, where growing economic wealth is opening new travel opportunities.
Aviation accounts for around 15% of global oil demand growth up to 2030 in the IEA’s New Policies Scenario, a similar amount to the growth from passenger vehicles. Such a rise means that aviation will account for 3.5% of global energy related CO2 emissions by 2030, up from just over 2.5% today, despite ongoing improvements in aviation efficiency.
This expansion underscores the need for the aviation industry to tackle its carbon emissions. For now, liquid hydrocarbon fuels like jet fuel remain the only means of powering commercial air travel. Therefore, along with a sustained improvement in energy efficiency, Sustainable Aviation Fuel (SAF) such as aviation biofuels are key to reducing aviation’s carbon emissions.
The International Civil Aviation Organization (ICAO), which governs international aviation, has committed to reducing carbon emissions by 50% from their 2005 level by 2050. Blending lower carbon SAF with fossil jet fuel will be essential to meeting this goal. This is reflected in the IEA’s Sustainable Development Scenario (SDS), which anticipates biofuels reaching around 10% of aviation fuel demand by 2030, and close to 20% by 2040.
The aviation industry demonstrates a strong commitment to sustainable aviation fuel use
The first flight using blended biofuel took place in 2008. Since then, more than 150,000 flights have used biofuels. Only five airports have regular biofuel distribution today (Bergen, Brisbane, Los Angeles, Oslo and Stockholm), with others offering occasional supply. But the centralised nature of aviation fuelling, where less than 5% of all airports handle 90% of international flights, means SAF availability at a small number of airports could cover a large share of demand.
Another indication of aviation’s commitment to growing SAF use is the agreement of long-term offtake agreements between airlines and biofuel producers. These now cumulatively cover around 6 billion litres of fuel. Meeting this demand will require further production facilities, and some airlines have directly invested in aviation biofuel refinery projects.
Still, aviation biofuel production of about 15 million litres in 2018 accounted for less than 0.1% of total aviation fuel consumption. This means that significantly faster market development is needed to deliver the levels of SAF production required by the aviation industry and keep on track with the requirements of the SDS.
Technology development is essential to increase aviation biofuel availability
Currently, five aviation biofuel production pathways are approved for blending with fossil jet kerosene. However, only one – hydroprocessed esters and fatty acids synthetic paraffinic kerosene (HEFA-SPK) fuel – is currently technically mature and commercialised. Therefore, HEFA‑SPK is anticipated to be the principal aviation biofuel used over the short to medium term.
Meeting 2% of annual jet fuel demand from international aviation with SAF could deliver the necessary cost reduction for a self-sustaining aviation biofuel market thereafter. Meeting such a level of demand requires increased HEFA-SPK production capacity. If met entirely by new facilities, approximately 20 refineries would be required. This could entail investment in the region of $10 billion. Although significant, this is relatively small compared to fossil fuel refinery investment of $60 billion in 2017 alone.
Ongoing research and development is needed to support the commercialisation of novel advanced aviation biofuels which can unlock the potential to use agricultural residues and municipal solid wastes. These feedstocks are more abundant and generally cost less than the waste oils and animal fats commonly used by HEFA-SPK, and can therefore facilitate greater SAF production. Furthermore, synthetic fuels produced from renewable electricity, CO2 and water via Power-to-Liquid processes may offer an alternative fuel source for aviation in the long term.
Improved aviation biofuel cost competitiveness with fossil jet kerosene is also needed
SAF are currently more expensive than jet fuel, and this cost premium is a key barrier to their wider use. Fuel cost is the single largest overhead expense for airlines, accounting for 22% of direct costs on average, and covering a significant cost premium to utilise aviation biofuels is challenging.
The competitiveness of SAF depends on its production cost relative to that of fossil jet kerosene (which varies with crude oil price). For all biofuels obtaining an economic feedstock supply is fundamental to achieve competitiveness, as feedstocks are the major determinant of production costs. For HEFA-SPK economies of scale could be realised by refineries designed for continuous production.
In the long term, airlines may include SAF consumption cost premiums within ticket costs. At current prices and today’s fleet average energy efficiency, the additional cost per passenger for a 15% blend of HEFA may not be high in comparison with other elements that influence ticket prices, such as seating class, the time of ticket purchase and taxation. However, due to the competiveness of the aviation industry customer price sensitivity is a core consideration for airlines.
Policy measures are crucial to stimulate sustainable aviation fuel demand
Impressive progress has been made in the utilisation of SAF since the first biofuel flight ten years ago. However, to fulfil aviation biofuels’ potential to reduce the climate impact of growing air transport demand, further technological development and improved economics are needed.
There is a key role for policy frameworks at this crucial early phase of SAF industry development. Without a supportive policy landscape, the aviation industry is unlikely to scale up biofuel consumption to levels where costs fall and SAF become self-sustaining.
Subsidising the consumption of SAF envisaged in the SDS scenario in 2025, around 5% of total aviation jet fuel demand, would require about $6.5 billion of subsidy (based on closing a cost premium of USD 0.35 litre between HEFA-SPK and fossil jet kerosene at USD 70/bbl oil prices). This is far below the support for renewable power generation in 2017, which reached $143 billion.
Other policy measures that could support SAF market development include:
- Financial de-risking measures for refinery project investments (e.g. grants, loan guarantees).
- Measures to provide guaranteed SAF offtake, e.g. mandates, targets and public procurement.
- Other mechanisms that close the cost gap between SAFs and fossil jet fuel e.g. carbon pricing.
Countries have more control over policy support for domestic than international aviation, and the introduction of national policy mechanisms to facilitate SAF consumption is gathering pace. The United States, the European Union, the Netherlands, the United Kingdom and Norway have all recently established policy mechanisms which will support the use of aviation biofuels. To gain the confidence of policy makers and the general public, such support will need to be linked to robust fuel sustainability criteria.
The Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), scheduled to be introduced in 2021, will be the principal mechanism to meet the ICAO’s long-term decarbonisation targets. SAF consumption and the purchase of carbon offsets are the two principal means to achieve CORSIA compliance, with the relative attractiveness of these to the aviation industry dependent on their cost per tonne of CO2 emissions mitigated.
A long-term view of natural gas security in the European Union
The security of European natural gas supplies has rarely been far off the political agenda. New gas pipeline and LNG projects command high levels of attention, particularly in the context of the European Union’s growing need for imports: its own production is declining; around 100 billion cubic metres (bcm) of long-term contracts expire by 2025; and there is some upside for gas consumption – at least in the near term – as coal and nuclear plants are retired. We estimate that the EU will have to to seek additional imports by 2025 to cover up to one-third of its anticipated consumption.
At the moment, Russia is sending record volumes to Europe while LNG utilisation rates remain relatively low. Limits to European production capacity and import infrastructure (with over half of pipelines operating at monthly peaks above 80%) may contribute to market tightness over the coming years, particularly if Asia continues to absorb the ramp up in global LNG liquefaction capacity.
Over the long-term, our projections in the latest World Energy Outlook suggest that Russia is well placed to remain the primary source of gas into Europe. LNG imports are projected to grow, as new suppliers – notably the United States – increase their presence on international markets and more European countries build LNG regasification capacity. However, Russia is still projected to account for around one-third of the EU’s supply requirements through to 2040.
But import dependence is only one part of the gas security equation. Less attention is being paid to three issues that may, in the long run, have an even greater impact on gas security in the European Union: how easily gas can flow within the European Union itself; how patterns of demand might change in the future; and what role gas infrastructure might play in a decarbonising European energy system.
A liberalised internal gas market
Whether or not gas can flow easily across borders within the European Union is a key focus of the EU’s Energy Union Strategy. On this score, our analysis suggests that the internal market is already functioning reasonably well: around 75% of gas in the European Union is consumed within a competitive liquid market, one in which gas can be flexibly redirected across borders to areas experiencing spikes in demand or shortages in supply. Bidirectional capacity has been instrumental in this regard.
That said, there are a few areas where markets and physical interconnections need further development. For example, roughly 80 billion cubic metres (bcm), or 40%, of the EU’s LNG regasification capacity cannot be accessed by neighbouring states, and some countries in central and southeast Europe still have limited access to alternative sources of supply.
On the whole, our projections suggest that targeted implementation of the European Union’s Projects of Common Interest (PCI) and full transposition of internal gas market directives can remove remaining bottlenecks to the completion of a fully-integrated internal gas market, thereby enhancing the security and diversity of gas supply. With LNG import capacity and pipeline projects like the Southern Gas Corridor increasing Europe’s supply options, the gas market in an ‘Energy Union’ case can build up its resilience to supply shocks while enabling short-term price signals, rather than fixed delivery commitments, to determine optimal imports and intra-EU gas flows.
However, this cannot be taken for granted. If spending on cross-border gas infrastructure were frozen and remaining contractual and regulatory congestion persists, then peak capacity utilisation rates would rise alongside the growth of European gas imports: around half of the EU’s import pipelines would run at maximum capacity in 2040 in this Counterfactual case, compared with less than a quarter in an Energy Union case.
Whether higher utilisation of the EU’s gas ‘hardware’ poses a security risk depends in large part on the strength of the ‘software’ of the internal market. The marketing of futures, swap deals and virtual reverse flows on hubs can allow gas to be bought and sold several times before being delivered to end-users. Along with more transparent rules for third party access to cross-border capacity, this might preclude some of the need for additional physical gas infrastructure and, in time, enable gas deliveries to be de-linked from specific suppliers or routes. Infrastructure investment decisions therefore require careful cost-benefit analysis, particularly as the debate about the pace of decarbonisation in Europe intensifies.
Security and demand
A second issue for long-term European gas security is the composition of demand. Winter gas consumption in the European Union (October-March) is almost double that of summer (April-September). The majority of this additional demand is required for heating buildings; this seasonal call is the primary determinant of gas infrastructure size and utilisation.
In the IEA’s New Policies Scenario, ambitious efficiency targets are projected to translate into a retrofit rate of 2% of the EU’s building stock each year, starting in 2021. Together with some electrification of heat demand, this would lead to a 25% drop in projected peak monthly gas demand in buildings by 2040.
This reduction in demand from the buildings sector more than offsets a 50% increase in peak gas demand for power generation, which is needed to support increasing amounts of electricity generated from variable sources, notably wind. Along with gradual declines in industrial demand, the net effect by 2040 is a reduction in monthly peak demand for gas by almost a third.
Such a trajectory for gas demand has significant commercial implications; reduced gas consumptions in buildings would lead to an import bill saving of almost €180 billion for the EU as a whole over the period 2017-2040. However, it also poses challenges for mid-stream players – e.g. grid and storage operators as well as for utilities:
For grid operators, structural declines in gas de21mand for heating means that the need for additional infrastructure is more uncertain, and what already exists may see falling utilisation (as discussed in WEO 2017). Capacity-based charges to end users typically contribute the most to cost recovery, and underpin the maintenance of the system. But, over time, higher operating costs for ageing infrastructure might need to be recovered from a diminishing customer base at the distribution level. This may further reinforce customer fuel switching over the long term.
For storage operators, the slow erosion of peak demand for heating implies an even more pronounced flattening of the spread between summer and winter gas prices, further challenging the economics of seasonal gas storage.
For utilities, with the anticipated declines in nuclear and the phasing out of coal-fired power plants in Europe, alongside the growth of variable renewable electricity, gas-fired power plants need to ramp up and down in short intervals in order to maintain power system stability. This flexible operation means a reduction in running hours but a continued need to pay for a similar amount of fuel delivery capacity (whether or not the gas itself comes from import pipelines or short-term storage sites).
A new set of questions for Europe’s gas infrastructure
The debate on Europe’s gas security has tended to concentrate on external aspects, mainly the sources and diversity of supply. But the focus may be shifting to internal questions over the role of gas infrastructure in a decarbonising European energy system, and the system value of gas delivery capacity.
A key dilemma is that, while Europe’s gas infrastructure might be needed less in aggregate, when it is needed during the winter months there is – for the moment – no obvious, cost-effective alternative to ensure that homes are kept warm and lights kept on. The amount of energy that gas delivers to the European energy system in winter is around double the current consumption of electricity.
Moreover, the importance of this function and the difficulty of maintaining it both increase as Europe proceeds with decarbonisation. As the European Union contemplates pathways to reach carbon neutrality in the Commission’s latest 2050 strategy, options to decarbonise the gas supply itself are gaining traction – notably with biomethane and hydrogen (we will be exploring these options in WEO 2019).
In order to stay relevant, natural gas infrastructure must evolve to fulfil additional functions beyond its traditional role of transporting fossil gas from the wellhead to the burner tip. Traditional concerns around security of supply of course remain relevant, but there are more things to value than volume. The security of the future gas system will increasingly depend on its versatility, flexibility, and the pricing of ‘externalities’ such as carbon emissions, air pollution or land use. Europe’s gas infrastructure is an undoubted asset. But, like many other pieces of energy infrastructure, it will need to adapt to the demands of sustainable development.
Batteries Can Help Renewables Reach Full Potential in Africa
Attractive costs for solar and wind power and cutting-edge innovations are making clean energy a compelling proposition in Sub-Saharan Africa, which faces the world’s largest gaps in electricity access. But solar and wind power are variable by nature, making it essential to find effective ways to store the electricity they produce to use when it is needed most.
Energy storage – batteries in particular – can help solve that problem.
Today, battery technology is costly and not widely deployed in large-scale energy projects. The gap is particularly acute in Sub-Saharan Africa, where nearly 600 million people still live without access to reliable and affordable electricity, despite the region’s significant wind and solar power potential and burgeoning energy demand.
Catalyzing new markets will be key to drive down costs for batteries and make it a viable energy storage solution in Africa.
A recent partner- and investor-focused conference sought to do just that.
The “Batteries, Energy Storage & the Renewable Future” event in Cape Town on Feb. 24 and 25 was attended by more than 200 participants from companies including Tesla, General Electric, Fluence, Siemens, the Southern Africa Power Pool, and national research labs and utilities from many countries.
South Africa’s Minister for Energy, Mr. Jeff Radebe, delivered opening remarks, and underscored the country’s commitment to the application of battery storage in its energy systems.
The event focused on the potential for batteries and other forms of energy storage to complement renewable energy by supporting off-grid and mini grids, which supply electricity to millions of people living in remote communities or areas that are not supported by traditional infrastructure.
It also demonstrated the tremendous demand that exists in the region today for energy solutions that do not just boost the uptake of clean energy, but also help stabilize and strengthen existing electricity grids and aid the global push to adopt more clean energy and fight against climate change.
Global demand for battery storage is expected to reach 2,300 GWh by 2030, while power systems around the world will need nearly ten times more — 22,000 GWh — of storage capacity by 2050 to integrate more wind and solar energy into the electricity grid.
The World Bank is already taking steps to address this growing need.
A new, first-of-its-kind $1 billion World Bank Group (WBG) program aims to help fast-track investments in battery storage by raising $4 billion more in public and private funds and convening a global think tank with the ultimate goal of financing 17.5 GWh of battery storage by 2025 – more than triple the 4-5 GWh currently installed in all developing countries.
“Last year, almost twice as many energy storage projects were announced globally – and the same is expected this year. The market is still small, but exponential growth has begun,” said Michael Solomon, the Chief Executive Officer of Clean Horizon.
To that end, the World Bank, in partnership with the Climate Technology Fund (CTF) and the African Development Bank, will support a large-scale distributed battery storage program in South Africa.
The WBG is also developing solar parks with 150 MW of PV and some 200 MWh battery storage each in Mali and Burkina Faso – the largest in the region. Other projects include a combined solar and battery storage project in Haiti, an emergency solar and battery storage power plant in the Gambia and mini-grids in island states to improve resilience.
In recent years, the WBG has also been working with other countries to support the deployment of batteries with solar and wind power, with projects currently under preparation in Africa, South Asia, Latin America and the Caribbean and the Pacific.
The World Bank event, “Batteries, Energy Storage & the Renewable Future,” was held in Cape Town, South Africa on Feb. 25-26, 2019 with the support of the Energy Sector Management Assistance Program (ESMAP) and the Middle East and North Africa Knowledge and Innovation Program (MENA KIP).
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