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Recommendations of the Global Commission on People-Centred Clean Energy Transitions
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Key trends to watch

Where are we at with clean energy stimulus?

As of the end of October 2020, governments around the world have announced USD 470 billion worth of energy-related stimulus packages targeting production and consumption. This stimulus is offered in the form of rebates, grants, loans and tax incentives/exemptions. The majority of these measures aim primarily to provide relief to public and private companies or consumers affected by the economic downturn arising from the Covid‑19 pandemic.

Announced stimulus packages targeting major energy production and consumption

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The aviation sector, including airlines and airports, is the largest stimulus recipient (USD 108 billion, of which USD 76 billion of airline bailouts), as movement restrictions have reduced the number of flights significantly. The ultimate goal of airline/airport bailouts was to prevent bankruptcies and layoffs (see Biofuels chapter for more detailed analysis of sustainable aviation fuels).

However, only the Air France-KLM, Austrian Airlines and Swiss Air stimulus packages set “green” conditions for bailout. Similarly, public sector transportation and railway companies together received USD 55 billion to maintain minimum operations. As part of the relief measures, governments have provided almost USD 90 billion to the electricity sector, not only to ensure the secure continuation of services but to reduce the energy bill burden of companies and individuals.

In addition to relief measures, governments (excluding the EU plan for economic recovery) also announced around USD 220 billion worth of energy-related stimulus packages, of which half (around USD 110 billion) targets clean energy technologies. The largest share of aid is aimed at raising the energy efficiency of existing buildings (through renovations), industrial processes, cars and ships. Renewable heat technologies are also expected to benefit from measures targeting energy efficiency (see Renewable Heat chapter for more details).

Announced clean energy stimulus packages by sector

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The transport sector including rail infrastructure, electric vehicles and charging infrastructure, aviation, biofuels, as well as active and public transport receives one third of the funds, mostly thanks to stimulus packages in France, Germany, China, and Canada.

New renewable electricity plants, mostly wind and solar PV, are expected to receive about USD 10 billion from announced stimulus packages (excluding the EU plan for economic recovery). Green hydrogen programmes are also expected to raise renewable capacity, although investors could also use existing wind, solar PV and hydropower plants for hydrogen production.

Announced stimulus packages for renewable electricity fall significantly short of the IEA’s sustainable recovery plan, in which around USD 180 billion would be spent globally each year from 2021 to 2023 on new wind and solar PV projects. Similarly, for biofuels the IEA plan envisions annual spending of USD 20 billion – ten times more than what governments had committed as of mid-September 2020.

With Next Generation EU, the European Union has put together EUR 750 billion (USD 840 billion) worth of stimulus to help member states recover from the pandemic, build up resilience and kick-start their economies. Stimulus is to be spent over 2021‑23, making additional resources of 1.6 times the EU annual budget available each year.

The package consists of grants (51%), loans (48%) and guarantees (1%) and is distributed across seven funds, with the Recovery and Resilience Facility (RRF) accounting for 90% of the total stimulus budget. Member states are expected to invest RRF funds in the seven priority areas of: clean energy technologies; energy-efficient building renovations; sustainable transport; broadband rollout; digitalisation of public administration; European cloud computing capacities; and mainstreaming digital skills into education systems.

In line with the European Green Deal, EU countries have agreed to explicitly include clean energy transitions at the heart of their economic recovery, with around 37% of total recovery money targeting climate-related expenditures, including clean energy technologies. Based on past (2014‑20) funding patterns, we estimate that the majority of climate-related investments are expected to materialise in infrastructure and transport (around USD 126 billion), followed by energy efficiency in buildings and industry (around USD 86 billion). We also anticipate that around USD 30 billion could be spent on new renewable electricity capacity and another USD 4 billion on biofuels.

Next Generation EU total and expected climate- and energy-related spending, 2021-2023

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The distribution of stimulus money across member states is based on country size, GDP and unemployment rate. Over two-thirds of total funds are thus likely to be allocated to Italy, Spain France, Poland and Germany. These countries could invest between EUR 19 billion and EUR 56 billion in areas with climate impact including energy, but concrete spending allocations across sectors will be not be known until member states submit their recovery and resilience plans between mid-October and the end of April 2021.

For renewable electricity alone, we estimate total 2021-23 funds available to member states to be more than three times the amount allocated through the European Structural and Investment Funds for 2014‑20. These loans and grants are likely to leverage additional private sector investments, which could be up to three times as high as stimulus funding. If 80% of total stimulus money for renewable power generation were spent on wind and solar PV equally, it could finance 20‑40 GW of solar PV and 10‑20 GW of wind plants across the European Union. As countries have already engaged in long-term planning to reach their 2030 renewables targets, this money is mainly expected to create additional liquidity to support those plans, rather than trigger additional capacity expansions.

Cumulative renewable electricity and biofuels spending from dedicated EU funds 2014-2023

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Clean energy stimulus by EU member states 2021-2023

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Are wind and PV expansion emerging beyond common policy schemes?

Policy support for renewable energy remains strong despite the Covid‑19 crisis. Although some governments have postponed the implementation of wind and PV auctions since March, the crisis has not provoked the cancellation of any major policy targets or incentives. In fact, some countries have announced ambitious decarbonisation plans and long-term net-zero emissions goals, including the European Union, China and Japan.

Policies have been key to achieve large-scale renewable energy deployment, costs reductions and innovation. The role of policies is changing, however, as wind and solar PV costs have fallen drastically in the past decade. Since 2015, countries have been rapidly transitioning from administratively set FiTs or floating FIPs to competitively set remuneration schemes (auctions, green certificates, etc.) for utility-scale or large-scale distributed PV projects. In the next five years, policy and regulatory frameworks enabling competition will underlie 60% of all renewable capacity expansion globally.

While auctions will remain the preeminent policy scheme, renewable energy expansion outside of government policies is emerging as a key trend. Corporate PPAs, merchant plants and projects receiving multiple revenue streams from tenders, spot markets and bilateral contracts are demonstrating new ways to allocate and diversify risks for wind and PV developers. From 2020 to 2025, the main driver of 9% of renewable capacity expansion is expected to be corporate PPAs and merchant plants, while another 7% is forecast to rely on multiple revenue remuneration schemes. In 2019, only less than 5% of renewable capacity additions were installed outside of main government policy schemes.

Renewable electricity capacity remuneration policy types, 2020-2025

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Tariffs that are set administratively will continue to be important for renewable energy expansion in China, as the government has phased out wind and PV subsidies. After 2021, new projects will receive fixed remuneration for 20 years at provincial benchmark electricity prices set by the government. Outside of China, FiTs and FIPs account for only 11% of global renewable energy expansion.

Will large oil and gas producers become major renewable electricity investors?

Since 2018, several oil and gas companies have announced ambitious emissions reduction targets through 2025‑30, with targets initially including scope 1 (direct) and scope 2 (indirect) emissions within company operations. As part of their strategies, oil and gas majors are increasingly involved in renewable electricity as equity investors, developers and/or off-takers of power. In 2019, oil and gas companies that are part of the Oil and Gas Climate Initiative (OGCI) had equity ownership in, and bought power from, about 5 GW of renewable electricity capacity, mostly wind and solar. In 2020, their involvement (including equity investments and power purchases in the renewable electricity sector) is expected to increase by over 50% to more than 8 GW, as many projects are already financed and under construction.

According to the announced targets and strategies of OCGI members, major oil and gas companies’ investments in new renewable electricity capacity are expected to increase ten-fold in the next five years. However, renewable energy growth will largely be driven by oil companies in regions where there are strong policy targets in place to reduce emissions. European companies are therefore projected to make up 95% of the renewable electricity capacity growth of oil majors through 2025. Oil producers in the United States and the Middle East have yet to announce significant renewable energy targets as part of their emissions reduction strategies. 

Installed and contracted renewable capacity by major oil and gas companies, 2018-2025

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Long-term net-zero emissions targets in the European Union and the United Kingdom are responsible for the sharp geographical variation. Despite significant growth, the oil and gas companies’ share of renewable capacity ownership and energy purchases remains minimal, projected to reach only 2% of total renewable installed capacity globally by 2025. Oil and gas production and sales are expected to remain their primary business activity in the upcoming decade.

Are system operators curtailing too much wind and solar electricity?

New load patterns caused mainly by the Covid‑19 demand shock and extreme weather conditions in some countries/regions have raised electricity security concerns. The curtailment, constraining or “dispatching down” of renewables has been receiving attention as a way for system operators to deal with the inflexibility of power systems during periods of oversupply. However, even though the amount of dispatched-down VRE-based electricity has increased in absolute terms, most systems have been able to evolve to accommodate more VRE.

The amount of dispatched-down energy in a region varies by month and season, depending on a variety of factors associated with system-wide reasons for curtailment (e.g. inertia, ramping limitations, contractual arrangements such as priority dispatch, etc.) and local network limitations or constraints (e.g. grid congestion, faults, etc.) (EirGrid, 2019). Moreover, changes in demand or supply due to climatic and weather conditions, which also affect wind and solar output, also determine how much energy is dispatched-down.

Furthermore, factors such as inadequate market design or system planning to integrate VRE sources; inappropriate locations and volumes for VRE installations; and a lack of flexibility in the electricity system and in infrastructure planning have led to the rise of dispatched-down electricity.

In key markets such as China and Germany, the absolute amount of dispatched-down wind and PV electricity rose 20-fold from 2010 to 2017, with most of the increase coming from China. Over 250 TWh of variable renewable electricity was curtailed – nearly the equivalent of Spain’s annual electricity demand. Had it been possible for this generation to be dispatched or stored for later use, emissions of 180 Mt CO21 could have been avoided, which is 3% of total US CO2-equivalent emissions in 2018 (EPA, 2020a).

Share of dispatched-down wind and solar PV generation in selected jurisdictions, 2010-2019

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Dispatched-down wind and solar PV generation in selected jurisdictions, 2010-2019

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China sustained high levels of dispatched-down VRE from 2011 to 2017 (7‑20%), reaching an absolute historical high at almost 50 TWh in 2016. This resulted from rapid deployment of wind capacity in northern provinces, where relatively low provincial demand, limited flexible generation, inadequate dispatch arrangements and interconnection capacity, and interregional trading constraints prevented maximum renewable output dispatch (IEA, 2019). In the same period, Germany, Spain, the United States and Australia also began to significantly dispatch-down wind and solar electricity, reaching almost 20 TWh in 2017.

Since 2017, however, China’s dispatch-down rates have declined significantly, mainly owing to the commissioning of additional interprovincial transmission capacity and improved market operations. The implementation of “investment warning” mechanisms that discourage new installations and project approvals in provinces with high curtailment rates has also helped. As a result of these measures, the share of curtailed VRE dropped from 17% in 2012 to less than 4% in 2019.

Even though dispatched-down VRE electricity overall has increased in absolute terms in the United States, Germany and Italy since 2017, the share of dispatched-down wind and solar PV output has remained stable at 1‑3%, which means that most systems have been able to evolve to accommodate increasing VRE generation as the capacity expands.

Record curtailment levels were reached in California in 2020, with the system operator (CAISO) curtailing over 318 GWh in April (7% of VRE output) – 67% more than in 2019. California had added 1 GW of wind and solar PV capacity from May 2019 to March 2020, raising VRE output, so monthly VRE shares over demand were at a record high of 29% in April 2020, driven by load-dropping of around 8% (mainly as a result of Covid‑19-related measures) at the same time as solar output peaked. Even though California’s maximum share of instantaneous VRE over demand has reached only 80%, the system’s lack of flexibility to accommodate this electricity has resulted in curtailment.

California demand, curtailment and VRE shares, 2020

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It must be remembered, however, that the optimal curtailment level is not necessarily zero. Dispatching-down can also be an effective way to cut peaks in generation, as it is not efficient for an entire system to have to accommodate exceptional periods of high VRE generation. Furthermore, it is not always logical from an economic perspective to build all the infrastructure that would be required to avoid dispatching-down (e.g. transmission lines, energy storage or more flexible capacity), as the costs may outweigh the benefits up to a certain point.

A transition to more system-friendly integration of variable renewables is needed, for example by complementing policy support schemes with exposure to competitive market outcomes, since there is little incentive for assets with fixed prices and prioritised dispatch to control outputs.

As VRE shares expand, incentivising (or removing barriers to) storage systems could further limit curtailment as well as foster demand-side flexibility. Storage systems incorporate not only large-scale batteries and pumped hydro, but distributed battery storage and technologies that can absorb electrical energy and then return it the same way later. Electricity storage technologies, including PSH and batteries, can provide multiple flexibility services ranging from the ultra-short to the long term, helping to accommodate increasing VRE shares (IEA, 2020). Batteries can contribute to ultra-short-term (sub-seconds) and short-term flexibility (hours to days), providing value by offering services such as fast frequency response and operational reserve.

As levels of absolute “wasted” (i.e. dispatched-down) renewable electricity rise, appropriate market designs; changes to the grid and to market operations; better forecasting; and efficient co‑ordination and operation of interconnectors will cost-effectively reduce curtailment. Modifying existing system assets (e.g. power plants and grids), investing in infrastructure and developing storage technologies and advanced VRE resources that have the capability to provide flexibility services, will also be necessary for reliable VRE integration.

It has been demonstrated that investments, along with important policy changes and co‑ordination, can significantly reduce curtailment. In Texas, for example, wind curtailment declined from 17% in 2009 to 3% in 2019 thanks to the Competitive Renewable Energy Zone (CREZ) policy, which directed transmission investments to high-potential areas where investments were most needed and also improved forecasting and regional co‑ordination for a larger balancing area. In China, transmission infrastructure investments, flexibility retrofitting of existing coal-fired power plants in some provinces, and the softening of administrative allocations to coal power plants in some provinces have reduced curtailment rates significantly.

Various actions on diverse fronts could be taken to eradicate system-wide barriers and permit proper VRE integration. Enabling VRE to compete in balancing markets would encourage the remuneration of real-time balancing costs and provide additional income for renewable generation, while exposing VRE to imbalance penalties would give producers an incentive to smooth their output and provide better forecasts either at the plant or regional level to reduce uncertainty. Furthermore, incentivising demand-side response, storage technologies and power to X to unlock flexibility and respond to shifts in demand would reduce the need to dispatch-down VRE generation, while designing markets to reflect actual system constraints by giving the right pricing signals would allow better allocation of investments. Some of these practices are already in place in markets such as Great Britain, Spain, Denmark and Australia, and among some system operators in the United States.

Are governments missing an opportunity to accelerate sustainable aviation fuel (SAF) deployment?

The Covid‑19 crisis has had a severe economic impact on the global aviation industry, with a significant proportion of airlines in need of financial assistance. Governments around the world have therefore acted swiftly to provide billions of dollars of financial support through direct subsidy payments, loans, loan guarantees and higher levels of ownership. This opens the door for governments to exert greater influence on airlines to reduce their climate impact.

However, most support has been provided free of any environmental or climate conditions, making a significant boost in the deployment of low-carbon aviation fuels unlikely. While SAF use is an important component in the aviation industry’s long-term CO2 emissions reduction goals, it accounted for only 0.01% of last year’s global aviation fuel consumption. Had government support been linked to SAF consumption, production could have been significantly accelerated, building on existing airline activities to develop lower-carbon fuels. 

The Covid‑19 crisis has had severe repercussions for the aviation industry. National and regional lockdowns have restricted travel, and even after their abrogation, ongoing travel restriction uncertainty has kept aviation activity well below pre-pandemic projections for 2020.

The International Air Transport Association (IATA), which represents the global airline industry, has indicated that air travel demand was almost 60% lower in the first half of 2020 than in 2019. The economic impact of the Covid‑19 crisis on the aviation industry could reach around USD 420 billion in 2020 (IATA, 2020).

In response to these unprecedented economic challenges, governments have rapidly provided financial support to the aviation industry. The IEA has analysed government financial support of 30 airlines across 21 countries, with these airlines representing 40% of the airline revenue passenger kilometres (RPK)2 registered in 2019, a key metric of passenger activity. This analysis revealed government support of around USD 76 billion as of August 2020, which is part of a wider USD 108 billion of support for the aviation industry as a whole. This figure is likely to increase over the coming months as other airlines also seek government support.

The government support can be broadly divided into four categories: direct financial aid, such as to cover salary payments or compensate financial losses due to the pandemic; government lending via state-owned banks; government guarantees for loans at commercial banks;3 and capital injections whereby governments raise their equity stakes in the airline.

Financial support to the aviation industry

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For 12 of the 30 airlines analysed, governments increased equity stakes through the injection of capital. This is more prevalent when other elements of the overall rescue package are publicly funded and the corresponding financial obligations for the airline are relatively low. When governments provide a loan guarantee, increased equity is less likely. 

Government financial support in relation to increased equity in airlines

Type of support

Financial value (USD billion)

Cases in which governments also increased equity in the airline

Direct aid

22.0

4 out of 8 (50%)

Government lending

21.5

7 out of 16 (44%)

Loan guarantees

13.0

1 out of 10 (10%)

When the share of government ownership in airlines increases, there is more potential to influence the airline’s activities to reduce its climate impact and support government efforts to meet climate change targets. Therefore, when governments with ambitious GHG emissions reduction targets increase their equity in airlines or introduce other policies to decarbonise aviation, they could spur greater SAF deployment.

This is already happening in the Nordic region. Norway established a 0.5% biofuel blending mandate for aviation fuel this year, and Sweden plans to introduce a GHG emissions reduction mandate for aviation fuel next year, starting at 0.8% and increasing gradually to 27% by 2030. France has proposed a 2% SAF blending level for 2025.

GHG emissions from international aviation fall outside of countries’ Nationally Determined Contributions (NDCs) under the COP21 global climate agreement, which may blunt the initiative of some countries to financially support emissions-reduction initiatives. GHG emissions from domestic aviation do, however, count towards NDC targets.

To understand how the Covid‑19 pandemic may impact SAF deployment, government financial support was assessed for the extent to which it is conditional upon companies altering their environmental and climate-related behaviours, including meeting low-carbon fuel blending requirements.

Overall, more than three-quarters of the government support analysed has been provided without any links to environmental performance. Of the 30 airlines, just four have to meet such conditions, which include reducing CO2 emissions; sustaining efficiency increases; and discontinuing some domestic routes that could be served by existing high-speed rail. Two airlines are subject to a 2% SAF blending requirement in the future. As these financial support packages are still under development, in many cases the finer details of the commitments and the extent to which they are binding remain unclear.

Government financial support to the aviation industry by type of conditions attached

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Current conditions attached to financial support for airlines to combat the Covid‑19 crisis will not provide the considerable boost needed to accelerate low-carbon fuel deployment. If fulfilled, the two cases in which governments require SAF blending would result in 110 million L of total consumption, assuming 2019 activity levels ­– equal to just over twice the 2019 SAF production of 50 million L (IATA, 2020). This additional demand is also relatively minor compared with the 6 billion L of multi-year SAF offtake agreements that several airlines had already entered into with production facilities for current and future supplies prior to the Covid‑19 pandemic.4

Had all 30 airlines been obligated to meet a 2% SAF blending requirement to receive financial support, this would have created around 2.7 billion L of demand annually, which is more than 50 times current production levels. This assumes a return to 2019 aviation activity levels,5 which may not occur until 2024 (IATA, 2020).

Although current SAF production capacity cannot service this demand level, establishing widespread blending requirements for the future (e.g. 2025) would provide demand certainty, which is essential to stimulate investment in SAF production facilities and scale up supply.

Existing HVO plants and new HVO projects in development would have been able to meet some of this hypothetical demand by dedicating a larger share of their refinery slate to hydro-processed esters and fatty acids (HEFA) aviation biofuel. To fully meet such a scale-up in demand would also require investments of around USD 2 billion in further SAF production capacity – just a small fraction of the Covid‑19 support provided to the aviation industry.

Is linking financial support for the aviation industry to the use of higher-cost SAFs feasible given the current economic strain on airlines? Fuel represents around 20% of operating costs on a global average basis, and more in some regions and certain market segments. Therefore, any requirement for airlines to use a higher-cost fuel raises questions about competitiveness with other airlines that do not have such a requirement – unless any requirement for airlines to use a higher-cost fuel applies to all companies operating in a given market, which is complex given the international nature of the aviation industry.

Even the most commercially available form of low-carbon aviation fuel, HEFA, is considerably more expensive than fossil jet kerosene. In 2019, the median HEFA production cost was roughly twice the market price of fossil jet kerosene. As jet kerosene costs have fallen by around 40% this year as a result of lower crude oil prices since the onset of the Covid‑19 pandemic, the cost of HEFA fuel is currently almost four times that of fossil jet kerosene. 

Fossil jet kerosene market price compared with HEFA aviation biofuel production cost, 2019-2020

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Although SAFs are currently considerably more expensive than fossil-based jet fuel, it can also be argued that airline fuel costs have fallen significantly in 2020 owing to the lower cost of fossil jet kerosene. Globally, the aviation industry’s 2020 fuel bill could be as much as USD 110 billion, or 72%, lower than in 2019 (IATA 2020), although this reduction also results from lower industry activity, which affects profitability.

Nevertheless, a 1% SAF blend rate applied across the entire industry in 2019 would have increased the aviation industry’s fuel bill by only USD 2.1 billion – equivalent to just 3% of the financial support provided to the 30 airlines analysed. Such a global SAF mandate would avoid giving any airline an unfair advantage and have a marginal impact on ticket prices. This measure would, however, require global approval through the International Civil Aviation Organization (ICAO) to apply to international aviation.

In the United States, eligibility for RFS2 policy support, the blender’s tax credit and opt-in provisions for aviation within California’s LCFS significantly reduces the cost premium of SAF consumption. Such robust policy support is not widely available, however.

Scaling up SAF output would also unlock the potential to realise economies of scale in production and supply, and to reduce non-feedstock costs. While nearly 80% of HEFA fuel production costs can be related to feedstocks, maximising production-per-cost potential in other areas of the SAF value chain will be crucial for commercial uptake. Furthermore, had further SAF requirements been imposed, this could also have delivered a boost to the production of other SAF technologies (such as Fischer-Tropsch aviation fuels) at an earlier stage of commercialisation than HEFA.

Airlines were already actively involved in SAF initiatives prior to the Covid‑19 crisis. Of the assessed companies receiving government support, almost half (14) from Asia, Europe and the United States already supported the use of alternative low-carbon fuels through a variety of means, as outline below. More widely, other airlines apart from those assessed have also been undertaking SAF initiatives.

SAF initiatives by assessed airlines

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While such initiatives will support greater SAF adoption over the medium term, current low-carbon fuel consumption remains minimal even among the airlines advancing its use. Airlines conducting regular flights with SAF blends account for only a very small share of overall aviation activity, and low-carbon fuel blending levels are generally low.

Furthermore, employing lower-carbon fuels is only one element of a wider range of measures that must be taken to robustly decrease GHG emissions from aviation. According to analysed airlines’ annual reports, CO2 emissions per passenger-kilometre generally fall within the range of 70-95 grammes of CO2 per RPK. Budget airlines demonstrate some of the lower emissions levels on an RPK basis, indicating that their very high passenger load factors offset higher fuel demand from short-haul flights. However, because budget airlines follow a cost-minimisation business model, reducing absolute CO2 emissions through the use of higher-cost SAFs is unlikely to occur without policy obligations.

Of the airlines analysed, some have ambitious long-term GHG emissions reduction targets that exceed the airline industry’s goal to cut net aviation CO2 emissions to 50% of the 2005 level by 2050. Several have even committed to reach net-zero GHG emissions by 2050 as part of the 13-airline “oneworld Alliance”. The airlines receiving government support have stated they intend to reduce their CO2 emissions through fleet renewal to improve fuel efficiency; research and development to raise aircraft energy efficiency; and optimisation of ground operations.

CO2 emissions-offsetting is also being used, either through direct pledges from airlines or voluntary commitments by passengers. This is unsurprising, as emissions-offsetting is the easiest way for airlines to comply with the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), at least initially.

Is it “full steam ahead” for renewable shipping fuels?

Unless renewable fuel consumption rises considerably, maritime shipping will have an increasingly negative long-term impact on the climate as international trade expands. A variety of low-carbon fuels are available for the shipping industry, and momentum for their use had increased prior to the Covid‑19 crisis. Currently, however, they all cost more than fossil marine fuels, which is the primary obstacle to increased consumption. The Covid‑19 crisis has further challenged the affordability of higher-cost fuels for marine shipping and uptake through corporate purchases.

Shipping accounts for three-quarters of all freight transport activity,6 with an overall energy demand of 221 million tonnes of oil equivalent (Mtoe) in 2019 (IEA, 2020a) – only slightly less than the final energy consumption of Brazil. Consequently, shipping accounted for 2.7% of all energy sector CO2 emissions in 2019 and one‑tenth of emissions from transport, creating a greater climate impact than any individual EU member state.

Unless actions are taken to reduce maritime shipping’s GHG emissions, its climate impact will increase considerably over the long term as international trade expands. If the shipping sector maintains its current policies while other parts of the energy system (e.g. the electricity sector, industry and other transport modes) embark on ambitious emissions reductions, its share of global CO2 emissions could rise to as much as 7% in 2040, putting shipping in the spotlight.

Consequently, the International Maritime Organisation (IMO) has committed to the long-term target of reducing absolute GHG emissions by 50% by 2050 (versus the 2008 level) and CO2 emissions per transport activity 40% by 2030. A comprehensive package of measures to achieve these targets is not yet in place, but a more detailed IMO strategy is due in 2023. Some industry participants have set more ambitious targets: for instance, Maersk, the world’s largest container ship operator, aims to attain net-zero emissions by 2050.

The key to reducing shipping’s climate impact is to tackle emissions from oceangoing vessels such as container ships and bulk carriers. Although these large vessels make up only one-fifth of the global shipping fleet, international marine bunker fuels account for 80% of all CO2 emissions from shipping.

Shipping is considered a hard-to-abate sector. Current regulations to address GHG emissions from ships7 are expected to raise average fleet energy efficiency by only 1.5% annually between 2015 and 2025. Even once design, technical and operational improvements have been maximised, the gap to meet the IMO’s emissions reduction target will likely still be considerable. Marine transport therefore needs to switch to very-low-carbon fuels.

The 20- to 35-year lifespan of marine freight vessels is a key consideration in the transition to alternative fuels. A significant proportion of the largest vessels currently in operation still have many years of service left, with two-thirds under 14 years of age (Equasis, 2018). “Drop-in” low-carbon shipping fuels suitable for the current shipping fleet with no or minimal modification to propulsion systems and associated infrastructure are therefore needed.

Long-term projections for international maritime freight indicate that the direct use of low-carbon hydrogen8 as well as ammonia produced from hydrogen and nitrogen from the air could be key future fuels for a low-carbon shipping sector. These are not drop-in fuels, however, so appropriate vessels, storage tanks and bunkering infrastructure are required for their use. Given that ships launched today may still be operational in 2050, suitable vessels need to be introduced by 2030 to maximise the potential of hydrogen and ammonia to help meet the IMO’s emissions goals.

Alternative shipping fuels overview

Fuel(s)

Drop-in?

Production status

Considerations and market developments

Biodiesel, HVO

Yes, for HFO and MGO ships

Commercialised

Specification superior to what is required for HFO ships, and better suited to vessels that use higher-cost MGO or in road transport. Have been consumed in demonstration initiatives.

Biofuel oil

Yes, for HFO ships

Output currently low, technology mature with certain feedstocks

Can be consumed with good performance in HFO-fuelled engines after little or no upgrading, offering more competitive pricing than alternatives (e.g. HVO). Have been consumed in demonstration initiatives.

BtL

Yes, for HFO and MGO ships

Not commercialised

Can potentially be produced from widely available forestry and agricultural residues. Would require minimal upgrading for use in HFO ships. Demonstration project in the Netherlands to produce marine BtL fuels in development.

Bio-LNG

Yes, for LNG ships

Commercialised

LNG demand as a shipping fuel set to increase tenfold by 2025 with fleet expansion (IEA, 2020b). EU funding allocated to establish bio-LNG bunker infrastructure in the Netherlands. Norwegian coastal ferry operator integrating biomethane consumption into its vessels.

Low-carbon hydrogen and ammonia

No, requires dedicated ICE or fuel cell propulsion

Early stage, currently limited availability

Increasing number of hydrogen strategies set to accelerate output. Ammonia shipping initiatives under way in Japan and the Nordic region. Testing of ammonia in marine engines has begun, and two ship OEMs planning to develop ammonia-fuelled engines for operation within the next five years.

Electricity

No

Currently unsuitable for international marine freight

Batteries need significantly higher energy density, and lower weight and cost, to be suitable for international shipping. Could be used for inland and short sea routes.

Notes: HFO = heavy fuel oil. MGO = marine gasoil. BtL = biomass-to-liquid fuel produced through thermochemical technologies such as gasification and pyrolysis. LNG = liquefied natural gas; bio-LNG signifies LNG produced from biomethane. Renewable hydrogen and ammonia are produced through electrolysis using renewable electricity, biomass gasification or steam methane reforming of natural gas with CCS. ICE = internal combustion engine. OEM = original equipment manufacturer. Hydrogen strategies have been released in several EU member states, in the European Union as a whole, and in Australia and Japan, among others. The logistical requirements for ammonia transport are already known owing to its established industrial uses, which is not the case for hydrogen.

Competitive bunkering costs are essential for commercial marine logistics services. Fuel can make up 50-60% of a shipping company’s operational expenses (Felby, 2018), although it varies according to the type of ship, service and oil prices. All low-carbon marine fuels currently cost more than incumbent fossil shipping fuels.

Indicative shipping fuel cost ranges

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Given these higher costs, stimulating low-carbon fuel consumption is challenging in the absence of a comprehensive policy framework to reduce emissions from international shipping, as well as incentives for low-carbon fuel use and widespread carbon pricing to cover shipping. Renewable fuels must also compete with an expanded use of LNG, which emits less CO2 than fuel oil, but not enough to fully meet the IMO’s 2050 goal on its own. The IMO strategy anticipated for 2023 will therefore be critical to facilitate cost reductions and provide a framework for low-carbon fuel deployment despite its higher cost.

IMO regulations that came into force in 2020 to reduce sulphur emissions from marine fuel use9 have prompted a switch from HSFO to more expensive VLSFO10 and distillate oil product fuels such as MGO. VLSFO consumption is therefore set to increase sixfold this year. All the low-carbon fuels in the table above are low in sulphur and comply with the IMO’s sulphur cap regulation.

From January to August 2020, VLSFO was 35-50% more expensive than HSFO at equivalent crude oil prices. Although market circumstances have been altered by the Covid‑19 pandemic and it is the first year of the IMO sulphur cap regulations, the pricing environment is dynamic.

Nevertheless, VLSFO becoming the dominant fuel for international shipping over the next few years should generally reduce the cost premium of sustainable shipping fuels – although most low-carbon alternatives will continue to be significantly more expensive. In addition, approximately 2 500 ships had been fitted with scrubbers by the end of 2019 and will still be able to use HSFO, representing around 6% of the total applicable HSFO fleet.

Increased standardisation (e.g. of fuel quality and bunkering) for all alternative shipping fuels will encourage their use. Unlike aviation, there is no legally binding fuel standard for the marine sector. Consequently, ship owners and operators eager to make their operations more sustainable are still wary about using new fuels and require assurance (e.g. through comprehensive trials) that their use will not have adverse effects.

The port of Rotterdam, one of the top three ports globally by bunker fuel sales, is home to a cluster of biofuel trial activity. Biofuel use is currently supported economically by a national scheme that allows renewable marine and aviation fuels to be used to meet EU RED targets.11 Tickets are awarded per unit of energy and have reached a value of up to EUR 0.60 per litre of biofuel, depending on fuel quality and feedstock. The scheme is currently undergoing revision. Rotterdam also intends to become a hub for low-carbon hydrogen.

Ports are also central in facilitating bunkering for renewable fuels. Just seven ports account for around 60% of global bunker fuel consumption (IRENA, 2020), so establishing supply chains to serve even one key port could extend the availability of alternative fuels to a considerable share of marine freight vessels. Reduced port fees for vessels using sustainable fuels is one means to stimulate demand.

Although providing regular sustainable-fuel supplies may be easier for liner vessels that have fixed schedules and routes, ensuring a suitable scale of production to meet demand remains a key challenge. In energy terms, the annual fuel demand of just one large seagoing container ship can be the same as for more than 100 000 gasoline-fuelled cars.

The global pandemic has created a more challenging environment for marine freight companies to adopt renewable fuels. In the first half of 2020, cargo and container volumes at ports across Asia, North America and Europe dropped by 10‑17%. In response to lower demand, container shipping companies have idled vessels and cancelled services (termed “blank sailings”), which may cause up to a 7% drop in activity (IEA, 2020d).

This difficult economic climate compounds the pressures of underlying debt burdens for container-shipping operators. The combined debt of 14 major companies reached USD 95 billion in 2019 (ITF, 2020), while last year’s profits amounted to only USD 6 billion (Financial Times, 2020). This clearly impairs the ability of companies to transition to higher-cost renewable fuels in considerable volumes.

At the same time, the drastic contraction in fuel demand caused by Covid‑19 has resulted in significantly lower fossil shipping fuel prices. Between December 2019 and early summer 2020, HSFO prices dropped 50%, LSFO 65%, MGO 60% and LNG around 60%.12 This obviously raises the relative cost of sustainable shipping fuels, and may consequently slow the uptake of demonstration initiatives in the absence of formal decarbonisation targets for maritime shipping. Realising the economies of scale in production and market development that are necessary to reduce the cost of sustainable fuels would therefore be delayed.

The crisis could also discourage companies that would normally procure lower-carbon shipping services to demonstrate their corporate social responsibility. For example, companies such as Ikea and BMW have supported biofuel consumption to reduce the climate impact of shipping their products. This kind of corporate offtake is important to enable investment in renewable marine fuel supplies, and can be encouraged by dedicated marine biofuel initiatives such as the GoodShipping Program.

With very few companies untouched by the crisis, the commitment to pay more for greener shipping services may be put to the test. Without a notable drop in the cost of sustainable fuels, their consumption in considerable volumes could translate into higher logistics costs for customers. This raises the prospect of some customers switching allegiance to companies that continue to use fossil fuels and can offer more affordable services.

However, transferring of business could also happen in places where government policies (e.g. carbon pricing) raise the cost of fossil shipping fuels, causing ships to change their bunkering location to areas where such policies are not in force. The inclusion of ships of 5 000 gross tonnage and above within the EU Emissions Trading Scheme (EU ETS) from 2022 was approved by the European Parliament in September 2020 and will be subject to further discussions with member states before introduction (European Parliament, 2020), while the European Green Deal has indicated that a review of tax exemptions for maritime fuels will be undertaken.

Conversely, measures included in some stimulus packages may boost the development of low-carbon shipping fuels. This includes EUR 1 billion of support pledged in Germany’s stimulus package for marine transport, as well as funds to develop hydrogen refuelling infrastructure for multiple transport modes. Meanwhile, Norway’s green transition package outlines support for “green shipping”.

References
  1. Based on US national weighted average CO2 marginal emission rate.

  2. RPKs indicate the distance travelled by paying passengers, i.e. the number of revenue passengers multiplied by the number of kilometres travelled.

  3. Typically covering 70-90% of the total loan amount. 

  4. Actual offtake levels depend on SAF availability at predetermined prices. 

  5. It also assumes a 1.5% annual fuel efficiency improvement for the fleet overall.

  6. Including inland shipping.

  7. The Energy Efficiency Design Index (EEDI) for new ships, and the Ship Energy Efficiency Management Plan (SEEMP).

  8. For example, produced through electrolysis using renewable electricity or through steam methane reforming of natural gas equipped with carbon capture and storage (CCS). 

  9. These regulations limit the sulphur content of maritime fuel used on board vessels trading outside sulphur Emission Control Areas to a maximum of 0.5%. Heavy Fuel Oil typically has 2.7% sulphur. 

  10. VLSFO is more expensive than HSFO because it contains more gas oil and enables shippers to meet the IMO regulations. Premium ultra-low-sulphur fuel oil (ULSFO) also exists. 

  11. The Netherlands is the only EU member state so far to apply this provision of the directive.

  12. The 60% LNG reduction refers to Asian spot and European prices; US prices fell less (by around 25%).

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