Nuclear Power Plants (NPPs) have long lifetimes and low running costs, but they require high up-front capital expenses and a long planning and construction time. This means the economics of NPPs are sensitive to the cost of financing and overruns, and project delays can be costly. Successful financing is a major challenge and typically requires significant government involvement.
Traditionally, the costs of constructing and operating nuclear power plants were mostly passed on to electricity consumers in the form of regulated tariffs, minimizing the risk to lenders, investors and operators of exposure to price fluctuation. This traditional approach characterized most pre-liberalization electricity markets, where many of the utilities were integrated monopolies combining generation, transmission, distribution and retail, and the level of government involvement in regulation
However, the market liberalization that started in the developed world in the 1990s has led to increased price and revenue uncertainty, causing reluctance among lenders and investors to commit the significant resources needed for NPP construction.
In an attempt to address this reluctance, stakeholders have come up with innovative approaches to risk sharing in nuclear power projects that aim to give additional assurance to potential lenders and reduce capital costs. These include reducing revenue volatility by guaranteeing electricity prices and providing various forms of government guarantees.
Replacing nuclear with nuclear: Why the UK model matters
Around 20 percent of the UK’s electricity supply today is produced by nuclear.
Within the broader context of its Electricity Market Reform, the Government has decided to continue to rely on nuclear rather than only on gas or renewable energy sources, and is seeking to replace its existing nuclear fleet.
Currently, developers have up to 11 reactors proposed or planned at six sites. The power plant at Hinkley Point C has already passed through several stages of the decision-making process and is expected to be commissioned in the early 2020s.
The UK model features three main mechanisms in support of nuclear: a price guarantee scheme known as contract for difference (CfD); a government guarantees scheme; and a mechanism for limiting investor exposure to the costs of disposing of higher activity waste, including spent nuclear fuel.
Contract for Difference
The CfD features a ratepayer-backed guaranteed price for electricity generated by low-carbon technologies. According to the terms of its CfD, Hinkley Point C, once operational, will be paid the difference (on a ‘per megawatt hour’ basis) between a ‘strike price’ (the electricity price that reflects the cost of investing in a particular low-carbon technology) and the ‘reference price’ — a measure of the average price for electricity in the UK market. When the average market price (the price that a generator such as Hinkley Point C might expect to receive directly from the sale of its electricity in the market) is lower than the strike price, the generator receives a ‘top up’ payment to make up the difference. When the average market price is higher than the strike price, the generator must pay back the difference.
“In the Hinkley Point C project, the CfD substantially mitigates the so-called ‘market risk’ faced by lenders and investors,” said Anurag Gupta, Director and Global Sector Head for Power Infrastructure and Corporate Finance at KPMG.
This gives electricity generators greater certainty and stability of revenues by reducing their exposure to volatile wholesale prices, while protecting consumers from paying for higher than necessary support costs when electricity prices are high.
“By creating greater certainty, investors and lenders are able to model the project, which in turn allows them to make more informed decisions,” explained Paul Murphy, Managing Director of Gowling WLG. “Furthermore, taking a 35-year tenure, as opposed to a classic 20-year tenure, facilitates further long-term equity investment as well as refinancing options.”
The UK Guarantees Scheme
The UK Guarantees Scheme (UKGS) is a mechanism developed by the UK Government to provide credit enhancement through debt guarantees. The scheme was introduced in 2010 with a budget of £40 billion in guarantees to be invested across a range of UK infrastructure categories, including energy, transport and social infrastructure. Support from this scheme has been made available to the Hinkley Point C project (for up to ₤2 billion worth of debt).
“It is instructive that the UK Government has concluded, based on years of analysis, that even in a market that has a long history with civilian nuclear power, government support is still needed to facilitate nuclear power development,” Murphy commented.
Limiting investor exposure to the costs of disposing of higher activity waste
One of the key issues associated with nuclear power is uncertainty with regard to the costs of disposing of higher activity waste, including spent nuclear fuel. The UK Government has put in place a mechanism to effectively cap such costs, thereby reducing operators’ exposure to the risk of cost escalation. The mechanism operates by setting an upper limit (or ‘cap’) on the ‘waste transfer price’ that an operator will have to pay in return for the UK Government taking ‘ownership’ of the higher level waste (and thus responsibility for its disposal).
“By effectively capping the ultimate waste transfer price, the UK Government has provided reassurance to potential investors regarding a very ‘difficult to quantify’ project risk,” explained Paul Warren, IAEA Senior Nuclear Engineer for Nuclear Power.
First published in International Atomic Energy Agency
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).
Consumers moving away from traditional forms of entertainment and media consumption
Consumers are increasingly using digital technology for more than just shopping. There is a revolution occurring in how consumers access entertainment...
Only on Langkawi: An Insider’s Guide to the Most Coveted Langkawi Pursuits
Whether in search of wanderlust, culture, or relaxation, Four Seasons Resort Langkawi showcases a bespoke collection of experiences that captures...
Smart cities hold the key to sustainable development
Asia and the Pacific’s phenomenal development has been a story of rapid urbanization. As centres of innovation, entrepreneurship and opportunity,...
Time and Place
OMEGA celebrates three great cities and the Swiss brand’s home country with a collection of exclusive boutique watches for passionate...
SDGs and Her Initiative Announces Winners of 2019 Global Competition
Today, the global SDGs and Her Competition announced the winners of the 2019 global competition. The contest– co-sponsored by the World Bank Group,...
India Acquiring Thermonuclear Weapons: Where Is The Global Outcry?
The atomic bomb revolutionized modern warfare not by enabling the mass slaughter of civilians but by vastly increasing its efficiency—the...
China’s Diplomatic Tightrope Amidst Rising Indo-Pak Tensions
Since the dramatic rise in Indo-Pak tensions earlier this month, the entire South Asian region has once again been propelled...
South Asia2 days ago
Countering Terrorism and the dawn of CPEC
Terrorism3 days ago
The Impact of Words: Christchurch Shooting
Middle East1 day ago
The battle for leadership of the Muslim world: Turkey plants its flag in Christchurch
Africa3 days ago
Here Are the 10 Young Africans Pushing Boundaries and Changing the World in 2019
Middle East3 days ago
Who Will Rebuild Syria: Extremely Loud & Incredibly Close
Intelligence3 days ago
Islamic Caliphate is dead, but its dangerous and infectious ideology is alive
Religion3 days ago
Hindu jihad (holy war): India Pakistan context
East Asia2 days ago
Xi Jinping’s visit to Italy and the relationship between China and the Catholic Church