Marking a milestone in the tumultuous journey towards a unified energy policy, the European Union (EU) member states have initiated joint procurement of a portion of their gas consumption. This coordinated effort has been facilitated through a gas purchasing mechanism, the AggregateEU, as of May 2023. In this policy brief we discuss the challenges this mechanism faces, given its design characteristics and the altered dynamics of the gas market following the energy crisis.
The necessity for a coordinated approach to energy security within the EU has been recognized at least since 2009, when its legal base was explicitly introduced in Article 194 of the Treaty of Lisbon. However, the de facto implementation of the solidarity principle has been lagging for many years. In response to the 2022 surge in gas prices, the EU has at last taken the solidarity approach to common energy security seriously. One of the most prominent steps is the creation of the AggregateEU mechanism, launched at the end of 2022. This mechanism aggregates the demand of registered buyers from different member states and matches it with competitive bids from external gas suppliers. It aims at improving and diversifying the EU gas supply, avoiding unnecessary buyer competition within the EU and building up the buyer power of EU member states. Furthermore, the mechanism is meant to reduce uncertainty and mitigate price volatility by providing information about accessible energy supplies. The mechanism covers both pipeline natural gas and Liquified Natural Gas (LNG) and organizes tenders every two months. While EU member states are required to submit demand bids for 15 percent of their 90 percent storage targets for the upcoming 2023-24 season through the mechanism, there is no obligation to sign any contracts based on the resulting match (more details can be found here and here).
The first three rounds of tendering via the mechanism, which took place May-October 2023, matched approximately 34 billion cubic meters of natural gas, exceeding the anticipated initial volumes. This outcome is currently perceived as a great achievement, enabling more vulnerable countries to benefit from coordinated purchases and resulting in increased bargaining power. Driven by this success, the European Commission (EC) has considered making demand aggregation via the mechanism a permanent feature of the EU’s gas market – and even extending it to hydrogen. However, while these agreed trades are a positive development, they may not reflect the mechanism’s overall success. Demand submission obligations may increase the number of demand calls which could project into more matches, but as they are not binding the subsequent agreements may not necessarily result in finalized contracts or lower prices.
In this brief, we argue that the mechanism’s benefits remain uncertain, primarily due to the current state of the EU’s gas market and the design flaws arising from efforts to address disparities in energy security among member states. These considerations call for a direct impact assessment, which however remains impossible due to the EC’s inability (or even reluctancy?) to collect and disclose the contracted outcomes resulting from the mechanism matches. This is especially problematic in light of the EC’s intentions to extend the mechanism’s coverage.
Limited Mechanism Benefits Under New Market Trends
Over the past two years, the EU has undertaken drastic efforts to address the energy security concerns within its gas market caused by the radical reduction in Russia’s natural gas exports to Europe. The EU has managed to sizably improve the diversification of its gas imports (see Figure 1), fill its storage facilities, and lower its gas demand (see McWilliams, Sgaravatti, and Zachmann (2021) and McWilliams and Zachmann (2023)).
Figure 1. Composition of EU natural gas imports.
As a result, a certain balance of supply and demand has been achieved, and the gas prices in the EU market have fallen to pre-war price levels (though they are still somewhat higher than their earlier long-term trend), as depicted in Figure 2. The ease of market tensions in 2023 has led many to argue that market forces are sufficient to resolve potential problems in the EU gas market and that mechanism costs would not be justified (see, e.g., Eurogas or International Association of Oil and Gas Producers opinions).
However, in the coming years the EU gas market is expected to be relatively tight due to capacity constraints both in the LNG market and for pipeline gas producers (as noted by, e.g., Bloomberg and IEA). This tightness makes the market highly sensitive to shocks, and a twofold increase in exposure to LNG – with its global liquidity – only adds to the problem. A good illustration of this concern is the recent market reaction to the Israel-Palestine war: the fear of supply disruptions lead to a whopping 55 percent increase in the European gas tariff TTF in the second week of October and to an EC initiative to prolong the emergency gas price cap, initially introduced in February 2023. This despite the EU’s gas storage nearing 98 percent of capacity and relatively low current prices.
Such a “seller market” situation implies that buyers’ ability to exercise buyer power and negotiate down prices may be highly limited when needed the most. Specifically, buyer power would be most effective when buyers have a credible outside option, e.g., the ability to claim that their gas demand needs can be facilitated elsewhere. The tighter the market, the more difficult it would be to find such volumes elsewhere, further limiting buyers’ ability to negotiate down prices. To put it differently: current market conditions may undermine the original purpose of the mechanism.
The current “shock-sensitivity” of the gas market may also give rise to additional concerns regarding the mechanism’s mere purpose – demand aggregation for vulnerable buyers. One of the by-products of demand aggregation is that (pooled) buyers are more likely to face correlated risks, e.g., by purchasing gas from the same producer. If markets are highly shock-sensitive – as they currently seem to be – such aggregation may further increase market volatility, implying that vulnerable buyers would be affected the most.
Figure 2. Natural gas prices in the EU, January 2021-October 2023 (prices in EUR).
Mechanism Design: Constraints vs. Efficiency
Some design elements of the purchasing mechanism may also challenge the mechanism’s ability to deliver an efficient outcome. First, quantity and price under the matching process are not binding, and buyers and sellers are expected to continue negotiations individually after the matching. This feature was introduced due to the concern that it would be challenging to offer a “one size fits all” binding contract to incorporate all participants of the pooled demand. This, as argued by Le Coq and Paltseva (2012; 2022), was one of the reasons for the previous failure to implement a mutual insurance and solidarity mechanism across the EU. However, the non-binding matching outcome will likely give rise to re-negotiations, price increases, and failure to exercise consolidated “buyer power”.
Moreover, a company can act on behalf of small or financially constrained buyers, purchase gas for them, and become an “Agent-on-behalf” and “Central Buyer”. In the process, companies will inevitably exchange sensitive information. This may limit competition and increase the market power of the “Central Buyer” company. In addition, firms may choose not to participate in the mechanism for at least two reasons. First, they may fear the threat of revealing valuable private information. Second, demand aggregation may discourage market participants with stronger buyer positions from participating, as being pooled with weaker participants would undermine their bargaining power. Both these cases would create a so-called adverse selection effect, where the more performant market participants would choose to avoid the joint purchasing mechanism. As a result, the joint buyer power may be strongly undermined, and the price-suppressing effect seems uncertain. This may explain why some firms, like several large German firms, have opted to sign long-term contracts with gas suppliers directly rather than via the mechanism
Several of these concerns arise not from the mechanism design per se but rather in combination with the inherent asymmetries between EU buyers, including variations in gas demand, risk exposure, etc. To put it differently: it is well justified that a “one size fits all” approach would fail in ensuring broad (and voluntary) mechanism participation; however, the choice of a more flexible solution, as implemented by the AggregateEU mechanism, creates commitment issues and adverse selection, and may undermine an effective use of buyer power.
Impact Assessment: Necessary but Currently Impossible
The new EU gas purchasing system is a significant step towards creating a unified energy policy. However, the design of such a procurement auction raises concerns about its contribution, especially under the new gas market dynamics. The current low gas prices make the immediate cost-benefit tradeoff of the mechanism nonobvious. More importantly, the tightness of the EU gas market in the next few years makes the “seller” power unlikely to be counteracted by the EU’s buyer power. Further, the absence of legal commitment between matched participants, and increased market volatility can lead to repeated ex-post renegotiations. These elements undermine the mechanism’s role and raise doubts about its benefits. Some of the mechanism’s inherent features, such as incentives for abuse of market power, also contribute to potential efficiency loss.
Hence, while the motivation behind this tool is clear, the implementation and potential design flaws may undermine the gains. It is therefore particularly important to understand whether the mechanism is effectively meeting its objectives, especially given the recent initiative to make it a permanent feature of the EU gas market and a key solution for the European Hydrogen Bank in the future. These considerations make a strong call for an impact assessment. An unbiased measure of AggregateEU’s impact would be necessary to assess the benefits of the mechanism (and to weigh them against the bureaucratic implementation costs). Currently, however, the EC has chosen not to collect, let alone disclose, the contractual outcomes resulting from matches. In a recent interview, Matthew Baldwin, deputy director-general at the EC’s energy directorate, said, “The reality is we’ve had relatively little feedback so far because companies are not required to give that to us in terms of the deals”. One may argue that many of the potential deficiencies of the mechanism design – e.g., non-binding matching and adverse selection – are justified by asymmetries across participants and other inherent market features. However, the absence of (appropriately desensitized) data about actual outcomes resulting from mechanism matches is more difficult to justify. The lack of data prevents us from evaluating the AggregateEU’s performance and raises additional concerns about its efficiency. Thus, gathering relevant information and conducting a comprehensive impact assessment based on sensible criteria are essential prerequisites for the future use, and expansion of the AggregateEU mechanism.
- Le Coq, C. and E. Paltseva. (2012). Assessing Gas Transit Risks: Russia vs. the EU, Energy Policy (4), 642-650. https://doi.org/10.1016/j.enpol.2011.12.037
- Le Coq, C. and E. Paltseva. (2022). What does the Gas Crisis Reveal About European Energy Security? FREE Policy Brief, https://freepolicybriefs.org/2022/01/24/gas-crisis-european-energy/
- McWilliams, B., Sgaravatti, G. and G. Zachmann. (2021). ‘European natural gas imports’, Bruegel Datasets. https://www.bruegel.org/publications/datasets/european-natural-gas-imports/
- McWilliams, B. and G. Zachmann. (2023). ‘European natural gas demand tracker’, Bruegel Datasets. https://www.bruegel.org/dataset/european-natural-gas-demand-tracker
Disclaimer: Opinions expressed in policy briefs and other publications are those of the authors; they do not necessarily reflect those of the FREE Network and its research institutes.
In the wake of Russia’s full-scale invasion of Ukraine, large parts of Europe have experienced skyrocketing energy prices and a threat of power shortages. The need to transition to low-carbon energy systems, driven by sustainability concerns, further adds to the pressure put on the European energy infrastructure. This year’s Energy Talk, organized by Stockholm Institute of Transition Economics, invited four experts to discuss the opportunities and challenges of energy infrastructure resilience in a foreseeable future.
Energy infrastructure has an indispensable role in facilitating the functioning of modern society, and it must – today as well as in the future – be resilient enough to withstand various challenges. One of the most important challenges – the green transition: shifting towards economically sustainable growth by decarbonizing energy systems and steering away from fossil fuels – requires energy infrastructure to absorb subsequent shocks. Another, and preeminent challenge, is that, even when directly targeted and partly destroyed as in the ongoing Russian war on Ukraine, energy infrastructure should be withstanding. Additionally, energy infrastructure is increasingly subject to supply chain disruptions, energy costs increase or network congestions. How does our energy infrastructure react to these challenges? How do they affect its ability to facilitate the needs of the green transition? Which regulations/measures should be implemented to facilitate energy infrastructure resilience?
Stockholm Institute of Transition Economics (SITE) invited four speakers to the 2023 annual Energy Talk to discuss the future of Europe’s Energy infrastructure resilience. This brief summarizes the main points from the presentations and discussions.
Energy System Resilience in the Baltics
Ewa Lazarczyk, Associate Professor at Reykjavik University, addressed the question of energy system resilience, focusing on the Baltic States and their dependence on Russia and other neighbors to fulfill their electricity needs.
The Baltic States are not self-sufficient when it comes to electricity consumption. Since 2009, Lithuania has become a net importer of electricity, relying on external sources to fulfill its electricity demand. Similarly, Estonia experienced a shift towards becoming a net importer of electricity around 2019, following the closure of environmentally detrimental oil fueled power plants.
The Baltics are integrated with the Nordic market and are heavily dependent on electricity imports from Finland and Sweden. Additionally, all three Baltic States are part of the BRELL network – a grid linking the electricity systems of Belarus, Russia, Estonia, Latvia, and Lithuania – which provides stability for their electrical networks. As a result, despite the absence of commercial electricity trading between Estonia and Russia, and limited commercial trading between Russia and the other two Baltic states, the power flows between the Baltic States and Russia and Belarus still exist. This creates a noticeable dependency of the Baltics on Russia, and a potential threat, should Russia decide to disconnect the Baltics from BRELL before the planned separation in 2024/2025.
This dependency was put on trial when Russia on May 15th 2022 cut its electricity trade with Europe. On the one hand, the system proved to be relatively resilient as the cut did not lead to any blackouts in the Baltics. On the other hand, price volatility amplified in its main import partner countries, Sweden and Finland, and congestion increased as compared to 2021.
Figure 1. Price volatility in Sweden and Finland before and after the trade cut.
This increased price volatility and congestion following the Russian halt in electricity trade gives an indication that the Baltics and the Nordics are vulnerable to relatively small supply cuts even at the current demand levels.
In the future, electricity consumption is however expected to increase throughout the region as a result of the electrification of the economy (e.g., by 65 percent in 2050 in the Nordic region). This highlights the need to speed up investments into energy infrastructure of internal energy markets.
In summary; recent events have demonstrated a remarkable resilience of the Baltic State’s electricity system. While the disruption of commercial flows from Russia did have some impact on the region, overall, the outcome was positive. Nonetheless, it is important to note that the region relies heavily on electricity imports, and with increasing demand for power in both the Baltics and the neighboring areas, potential issues with supply security could arise if the demand in the Nordics cannot be met through increased production. The risk of an early disconnection from the BRELL network further amplifies this concern. However, the case of Ukraine – which managed to abruptly disconnect from Russian electricity networks – serves as an example that expediting the process of establishing new connections is feasible, although not risk free.
The Ukrainian Energy Sector and the Immediate Threat from Russia
While the Baltics are facing the effects from the Russian halt in electricity trade and the threat of a potential premature disconnection from BRELL, Ukraine’s energy networks are at the same time experiencing the direct aggression from Russia.
Yuliya Markuts, Head of the Center of Public Finance and Governance at the Kyiv School of Economics (KSE), and Igor Piddubnyi, Analyst on Energy Sector Damages and Losses and Researcher at the Center for Food and Land Use Research at KSE, both gave insight into the tremendous damages to the Ukrainian energy system from Russian attacks, the short-term solutions to cope with the damage, as well as the long-term implications and reconstruction perspectives.
Since the invasion, about 50 percent of the energy infrastructure has been damaged by shelling. In addition, several power plants are under Russian control or located in Russian occupied territories. As of February 2023, nearly 16 GW of installed capacities of power plants remained in Russian control, equivalent of the peak demand. Apart from the damages to the producing side, transmission and distribution facilities have also been severely affected, as well as oil storage facilities. In April 2023, the damages to Ukraine’s energy infrastructure were estimated to amount to $8.3 billion, almost 6 percent of the total estimated direct damages from the war.
While the damages are massive, the population did not experience complete blackouts, and the Ukrainian energy system did not collapse. This is partly due to diesel-driven generators substituting much of the damaged electricity generation and partly due to a fall in demand of about 30-35 percent in 2022, mainly driven by decreased industry demand.
In the short term, Ukraine is likely to continue to face Russian attacks. Its top energy priorities would thus be to restore damaged facilities and infrastructure like heating and clean water, increase the stocks of fuel, gas, and coal, and to try to liberate occupied areas and facilities. Another vital aspect of the Ukrainian energy infrastructure and its resilience towards the Russian goal of “freezing” the country relates to energy efficiency. Ukraine’s energy efficiency has been relatively low, with the highest rate of electricity losses in Europe, and the numbers are also high for gas supply and district heating. Here, minor changes such as light bulb switching, can have great impacts. Additionally, solar panels – especially those that can also store energy – can help alleviate the acute pressure on the transmission grid. Other vital measures involve continued donations from Ukraine’s partners, sustained efforts from energy workers – at the risk of their lives – and persistent successful deterrence of cyber-attacks currently targeting the country.
Achieving a greener energy system is currently challenging (if not nearly impossible) due to the use of diesel-driven generators, the attacks on the energy system, and the fight for control over nuclear power plants such as Zaporizhzhia, which since March 2022 is under the control of Russian forces. Damages to renewable energy production further exacerbate these difficulties.
Thus, it is crucial to ensure that the planning and reconstruction of Ukraine’s energy sector is done in accordance with the European Green Deal. By 2030, the country should have at least 25 percent renewables in its energy mix, which would require substantial installations of at least 13 GW of wind, solar, small hydro and biogas capacities. In addition, transition entails decommissioning old coal power plants to run on natural or biogas instead of coal.
While this is a tall task, investments targeted to the energy system are not only essential for Ukraine’s population to sustain through the 2023/2024 winter – but also to facilitate the green transition in Europe. The potential for export of biomethane, green hydrogen, and nuclear power from Ukraine to Europe is considerable. As Europe’s biofuel demand is expected to increase by 63 percent while Ukrainian grain exports are still proving to be challenging, biofuel production for export on the European market is a particularly likely future scenario for the Ukrainian energy market.
In summary; the Ukrainian energy sector has done remarkably well, considering the impact of the damages from the Russian aggression. As Ukrainian short-term energy priorities lie in facilitating quick and efficient responses to infrastructural damages, current measures may not be particularly environmentally friendly. However, the longer-term reconstruction of Ukraine’s energy sector has great potential for being in line with the green transition objectives.
Energy System’s Resilience in the Green Transition
Mikael Toll, Senior Advisor at Ramboll Management Consulting highlighted the importance of infrastructure resilience. He emphasized the significance of the Energy Trilemma in achieving a successful transition to greener energy systems. This trilemma implies balancing between energy security, environmental sustainability, and affordability, all representing societal goals. Focusing on the energy security aspect of this trilemma, he stressed that energy infrastructure should be part of a more holistic approach to the problem. It is essential to establish resilient supply chains and implement efficient management procedures to prevent and mitigate the negative consequences of disruptions. It entails ensuring the performant infrastructure and supply, but also fostering well-functioning markets, putting in place state-governed crisis management mechanisms, and cooperation with other states. By combining these elements, one can enhance preparedness both in normal times and during crises.
Sweden as an Example
Sweden has since long been increasing its share of renewables in the energy mix, as depicted in Figure 2. This suggests that it is relatively well-prepared to the needs of the green transition. However, electricity demand is expected to increase by 100 percent in the coming years, driven by increased electrification of the industry and transport sectors, adding pressure to Sweden’s electricity system. The need for more investments in several energy systems is tangible, and investment opportunities are numerous. However, political decisions concerning the energy system in Sweden tend to be short-sighted, even though energy infrastructures have a long lifespan – often well over 50 years. As a result, investment risks are often high and change character over time, which creates a lack of infrastructure investment. Other challenges to Sweden’s energy resilience include limited acceptance of new energy infrastructure among the public, time-consuming approval processes, and a lack of thorough impact assessment.
Figure 2. Total supplied energy in Sweden, 1970-2020.
Further, the current geopolitical context creates an increased need to consider external threats – such as energy system disruptions resulting from the Russian war on Ukraine – and increased dependency on China as a key supplier of metals and batteries required for electrification. It is also important to realize that external influence may affect not only physical infrastructure but also domestic decision-making processes. This calls for more energy and political security alongside the green transition, in combination with higher readiness against security threats and a reassessment of global value chains.
In summary; to successfully move into a greener future, it is necessary to invest in energy systems and infrastructure based on a careful multi-dimensional analysis and with the support of long-sighted political decisions. At the same time, we must push investments that also consider the security threats from and dependencies on global actors.
This year’s Energy Talk provided an opportunity to hear from leading experts on the current situation of Europe’s energy resilience. It outlined the key challenges of the green transition in the current geopolitical and economic context. Greener solutions for Europe’s energy system will require tremendous physical efforts and investments but also political will and public understanding. There are, however, immense benefits to be realized if the associated risks are not overlooked.
On behalf of the Stockholm Institute of Transition Economics, we would like to thank Ewa Lazarczyk, Yuliya Markuts, Igor Piddubnyi and Mikael Toll for participating in this year’s Energy Talk. The presentations from the webinar can be seen here.
- Swedish Energy Agency. (2022). Energy in Sweden 2022 – an overview. https://energimyndigheten.a-w2m.se/Home.mvc?ResourceId=208766
- Lazarczyk, E. and Le Coq, C. (2023). Power coming from Russia and Baltic Sea Region’s energy security. REPORT 2023:940. Energiforsk.
Disclaimer: Opinions expressed in policy briefs and other publications are those of the authors; they do not necessarily reflect those of the FREE Network and its research institutes.
Although much smaller than Russian exports of other energy commodities, Russian electricity exports to Europe have been a part of the European electricity systems. There are several connection points between the Russian and EU markets, but the Baltic States are the most exposed to Russian influence in the electricity sector. This brief discusses the Baltics’ dependency on Russian electricity, which currently accounts for 10 percent of the total Baltic electricity consumption. We argue that, while the Baltic states have some resilience (partly due to their connection to the Nordic countries), they are not immune to a complete halt to the Russian electricity trade, at least not in the short run.
The continuing military conflict in Ukraine and cut-offs of Russian gas to Europe are driving energy prices to unprecedented levels and creating concern about energy security all over Europe. The reliance on the Russian gas supply and the consequences of this has been profoundly discussed (for an overview, see e.g., Le Coq and Paltseva, 2022). At the same time, the topic of Russian electricity delivered to the EU has been largely left out of the current conversation.
Russia is exporting electricity directly to Europe, although at a much smaller scale than it has been exporting other energy commodities. There are several transmission connection points between the Russian and EU markets, but the situation of the Baltic States is the most precarious. They consume Russian electricity (about 10 percent of their needs) and their grids are still synchronised with Russia and Belarus. Therefore, they are exposed to some supply disruption and a desynchronization threat from Russia, potentially resulting in high market prices, severe congestion and even blackouts. Because the Baltics are connected to the leading power market in Europe, Nord Pool, any unexpected shocks may have consequences beyond the Baltic region.
Understanding how the Baltic States depend on Russia for their power consumption is an important element of the European energy security debate. This brief discusses the severity of the Baltics’ reliance on Russian electricity. We initially discuss the effect of a sudden halt to the Russian electricity trade in May 2022. We then address the potential consequences of the abrupt exclusion from the Russia-controlled transmission network. Finally, we discuss the future energy mix thought to replace Russian electricity in the Baltics.
The Baltic States’ Exposure to Indirect Imports of Russian Electricity
The Baltics’ exposure is analysed by examining the impact of a sudden stop of imports of Russian electricity to the EU in May 2022, which affected Nord Pool (https://www.nordpoolgroup.com/en/) prices as well as congestion in the Baltic States. This event cannot be qualified as an external shock, required for a rigorous empirical analysis. Nonetheless, it helps us assess the Baltics’ exposure.
On May 15th 2022, Russia broke off its electricity trade with Finland. This event is relevant to consider as Finland is increasingly a primary import source for the Baltic States. Any electricity supply disruption affecting Finland may therefore impact the Baltics’ energy system balance. To assess how the event impacted the Baltic electricity market, we compare the congestion occurrences in 2021 and 2022.
A standard way to assess the misfunctioning of a power market is to look at congestion episodes. The Nord Pool market, to which the Baltic states are connected, has several bidding areas. Prices between zones may differ in case of transmission bottlenecks. When transmission lines are saturated, no more electricity can, in that period, be transported from the cheap to the expensive areas to alleviate prices, referred to as congestion.
In the graphs below, we illustrate the congestion in the Baltics in 2021 as compared to 2022. Looking at the 2021 data for Estonia and Latvia, the countries belonged to the same price area most of the year; some price differences were observed in the summer months, but only 10 percent of the hours within those months were congested. In 2022 the price differences between the two countries grew substantially, since May reaching 20 percent, with more congested hours (Figure 1). In 2022 price differences also increased between Lithuania and Southern Sweden (region SE 4) as depicted in Figure 2.
Figure 1. Congestion between Estonia and Latvia (as percentage of congested hours out of all hours within a given month).
Figure 2. Congestion between Lithuania and Sweden (SE4) (as percentage of congested hours out of all hours within a given month).
Our aim is not to show a causal effect of the withdrawal of Russia from commercial electricity trading with the Baltic States region, but to describe some general, coincidental trends in congestion. Note that the congestion might be a result of the extreme prices observed in the Baltics – on August 17th 2022, prices reached the Nord Pool cap of 4000€/MW, the highest ever level in the region (Lazarczyk Carlson and Le Coq, 2022a).
To conclude, halting the electricity trade between Russia and Finland appears to have had some impact on the congestion in the Baltic States. Still, the consequences were not severe as the Baltics were already curtailing commercial exchanges with Russia and Belarus. Additionally, the Finnish yearly imports from Russia constituted at most 10 percent of the annual Finnish consumption.
The Baltic States’ Exposure to a Desynchronization Threat
The Baltics belong to the Moscow-controlled synchronous electrical power grid, BRELL, which connects power systems of Belarus, Russia, Estonia, Latvia and Lithuania. This grid dependency makes it virtually impossible for the Baltic States to completely stop Russian and Belarussian power from floating into the Baltics´ territory. A desynchronization from the BRELL network is currently not feasible. Although the Baltics have invested heavily in grid extensions and upgrade, the connection to the European grid is scheduled only for 2024/2025. Therefore, even though the Baltic States have been limiting commercial trading with Russia and Belarus on the Nordic electricity market, they are still receiving Russian/Belarusian electricity.
The Baltics’ dependency on the BRELL network creates a potential threat to the Baltic electricity supply security in case Russia should decide to weaponize its electricity supply further and disconnect the Baltic States from the network ahead of the planned exit in 2024/2025 (Lazarczyk Carlson and Le Coq, 2022a). Such premature disconnection could result in severe blackouts, and immediate reactions would be required to keep the system operational. In such scenario, strong support from the Nordic countries via Finland and/or Sweden would be needed. It is however important to keep in mind that a sudden disconnection from BRELL also could harm Kaliningrad – the Russian enclave between Lithuania and Poland, on the shores of the Baltic Sea. Although Russia has invested heavily in expanding Kaliningrad generation capacities and its energy self-sufficiency, it is not clear whether the region is to this day prepared to operate in island mode without the support of the BRELL and neighbouring countries. Up to date, three successful operating exercises in island mode have been conducted in Kaliningrad, the longest lasting for 72 hours. However, the two tests scheduled for 2022 have been cancelled.
The future re-initialization of electricity trading with Russia is uncertain at this point and the role of Russian electricity has diminished over the years. The Baltics are not planning to maintain any transmission connection with Russia and Belarus after synchronising with the European power grid. However, the Finnish standpoint needs to be clarified. If the Finnish-Russian electrical power trade exchange is re-established in the future, Russian electricity might once again flow into the Baltics´ transmission grid as imports from Finland are forecasted to increase in the coming years due to a third interconnector, which should become operational in 2035.
The Baltics’ (Future) Energy Mix Without Russian Electricity
The alternatives to Russian electricity depend on the Baltics’ energy mix and transmission system. In 2021 the demand for electric power in the Baltics was 27 TWh, with Latvia representing 26 percent, Estonia 30 percent, and Lithuania 44 percent of the total demand. Consumption is forecasted to grow by 60-65 percent by 2050, due to the electrification of the economy and increasing needs within industries, housing, transportation, etc. (Nordic Energy Research, 2022).
All Baltic States are today net importers of electricity. The main import sources are Finland and, to a lesser extent, Sweden, which have jointly exported 45 TWh of electric power to the region over the years 2016-2021. Finland is itself a net importer of electricity mainly importing power from Sweden. Until May 2022, Finland’s second import source was Russia.
The Baltics are heavily dependent on fossil fuels in their electricity mix as illustrated in Table 1.
Table 1. Energy mix for electricity production (MW) in the Baltics, 2022.
The region is now trying to limit the use of fossil-fuel energy and expand its green energy potential, as extensively discussed in Lazarczyk Carlson E. and Le Coq C. (2022b). The actual installed capacity for the onshore wind is however insufficient, with 326 MW in Estonia, 87 MW in Latvia, and 671 MW in Lithuania. The current offshore wind’s capacity is non-existent. There are some plans to develop 4.5 GW in Lithuania, 7 GW in Estonia, and 14.5 GW in Latvia by 2050, but this will require substantial investments (European Commission, 2019).
The region also plans to expand solar power production, especially in Latvia and Lithuania, where the current capacity is 14 and 259 MW respectively. There are also plans to expand Latvian hydro production for storage and balancing needs; currently, Latvia has 1588 MW of installed run-of-the-river hydro capacity, the highest among the Baltic States.
Investing in nuclear power is another possibility which is currently being considered. As part of the EU accession process, Lithuania shut down its Ignalina Nuclear Power Plant, the first unit in 2004 and the second in 2009, turning the country from a net exporter into a net importer of electric power (IEA, 2021). A project of replacing the Ignalina Nuclear Power Plant (NPP) by a new Polish-Lithuanian Plant, the Visaginas NPP, was discussed but later abandoned. The Estonian company Fermi Energy, in collaboration with the Swedish firm Vattenfall, are currently looking into small modular reactor (SMR) technology to develop nuclear energy. This project is however in the initial phases of development.
Renewables and nuclear power are credible alternatives to limit fossil-fuel energy usage and dependency on Russian electricity. The alternatives might however not be easily implemented in the short run.
The Baltic States’ dependency on the Russian electricity supply is limited. Nevertheless, discontinuing Russian electricity deliveries is not innocuous for at least two reasons.
First, the Baltics are still part of the BRELL network, so they are still physically dependent on Russia, although they plan to desynchronize from this network in the longer run. However, a sudden desynchronization initiated by Russia may have severe consequences in the short run (e.g. blackouts).
Second, considering the forecasted future increase in the demand for electrical power in the Baltics and the Nordic countries, the Baltics will remain dependent on power imports. Today, the Baltics rely on Finland and Sweden, as all three Baltic States are net electricity importers. To limit any future dependence on Russian/Belarussian electricity, the Baltics plan to sever any transmission connections with Russia and Belarus after desynchronization, thus cutting the potential for future electricity trade with both countries. If, however, the Nordic countries re-establish commercial exchanges with Russia via Finland, it is nevertheless possible that Russian electricity will be flowing in the Baltics transmission system again.
This policy brief is based on a project funded by the Energiforsk research program.
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- Nordic Energy Research. (2022). Baltic-Nordic Roadmap for Co-operation on Clean Energy Technologies. Accessed on the 12th of November 2022 from https://www.nordicenergy.org/publications/baltic-nordic-roadmap-for-co-operation-on-clean-energy-technologies/
- Nord Pool. Accessed on the 28th of November from https://www.nordpoolgroup.com/en/
Disclaimer: Opinions expressed in policy briefs and other publications are those of the authors; they do not necessarily reflect those of the FREE Network and its research institutes.
Policymakers in Europe are currently faced with the difficult task of reducing our reliance on Russian oil and gas without worsening the situation for firms and households that are struggling with high energy prices. The two options available are either to substitute fossil fuel imports from Russia with imports from other countries and cut energy tax rates to reduce the impacts on firms and household budgets, or to reduce our reliance on fossil fuels entirely by investing heavily in low-carbon energy production. In this policy brief, we argue that policymakers need to also take the climate crisis into account, and avoid making short-term decisions that risk making the low-carbon transition more challenging. The current energy crisis and the climate crisis cannot be treated as two separate issues, as the decisions made today will impact future energy and climate policies. To exemplify how large-scale energy policy reforms may have long-term consequences, we look at historical examples from France, the UK, and Germany, and the lessons we can learn to help guide us in the current situation.
The war in Ukraine and the subsequent sanctions against Russia have led to a sharp increase in energy prices in the EU since the end of February 2022. This price increase came after a year when global energy prices had already surged. For instance, import prices for energy more than doubled in the EU during 2021 due to an unusually cold winter and hot summer, as well as the global economic recovery following the pandemic and multiple supply chain issues. Figure 1 shows that the price of natural gas traded in the European Union has increased steadily since the summer of 2021, with a strong hike in March 2022 following the beginning of the war.
Figure 1. Evolution of EU gas prices, July 2021-May 2022
Concerns about energy dependency, towards Russian gas in particular, are now high on national and EU political agendas. An embargo on imports of Russian oil and gas into the EU is currently discussed, but European governments are worried about the effects on domestic energy prices, and the economic impact and social unrest that could follow. Multiple economic analyses argue, however, that the economic effect in the EU of an embargo on Russian oil and gas would be far from catastrophic, with estimated reductions in GDP ranging from 1.2-2.2 percent. But a reduction in the supply of fossil fuels from Russia would need to be compensated with energy from other sources, and possibly supplemented with demand reductions.
In parallel, on April 4th, the Intergovernmental Panel on Climate Change (IPCC) released a new report on climate change. One chapter analyses different energy scenarios, and finds that all scenarios that are compatible with keeping the global temperature increase below 2°C involve a strong decrease in the use of all fossil fuels (Dhakal et al, 2022). This reduction in fossil fuel usage over the coming decades is illustrated in red in Figure 2.
It is thus important that, while EU countries try to decrease their dependency on Russian fossil fuels and cushion the effect of energy-related price increases, they also accelerate the transition to a low-carbon economy. And how they manage to balance these short- and long-run objectives will depend on the energy policy decisions they make. For instance, if policymakers substitute Russian oil and gas with increased coal usage and new import terminals for LNG, this can lead to a “carbon lock in” and make the low-carbon transition more challenging. In this policy brief, we analyze what lessons can be drawn from past historical events that lead to large-scale structural changes in energy policy. Events that all shaped our current energy systems and conditions for climate policy.
Figure 2. Four energy scenarios compatible with a 2°C temperature increase by 2100.
Structural Changes in Energy Policy in France, the UK, and Germany
We focus on three “energy policy turning points” triggered by three geopolitical, political or environmental crises: the French nuclear plan triggered by the 1973 oil crisis; the UK early closure of coal mines and the subsequent dash for gas in the 1990s, influenced by the election of Margaret Thatcher in 1979; and the German nuclear phase-out triggered by the 2011 Fukushima catastrophe.
In response to the global oil price shock of 1973, France adopted the “Messmer plan”. The aim was to rapidly transition the country away from dependence on imported oil by building enough nuclear capacity to meet all the country’s electricity needs. Two slogans summarised its goals: “all electric, all nuclear”, and “in France, we may not have oil, but we have ideas” (Hecht 2009). The first commissioned plants came online in 1980, and between 1979-1988 the number of reactors in operation in France increased from 16 to 55. As a consequence, the share of nuclear power in the total electricity production rose from 8 to 80 percent, while the share of fossil fuels fell from 65 to 8 percent.
Figure 3. French electricity mix
In the UK, the election of Margaret Thatcher in 1979 opened the way for large market-based reform of the energy sector. Thatcher’s plan to close dozens of coal pits triggered a year-long coal miners’ strike in 1984-85. The ruling Conservative party eventually won against the miners’ unions and the coal industry was deeply restructured, with a decrease in domestic employment – not without social costs (Aragon et al, 2018) – and an increase in coal imports. At the same time, the electricity market’s liberalization in the 1990s facilitated the development of gas infrastructure. As an indirect and unintended consequence, when climate change became a prominent issue at the global level in the 2000s, there was no strong pro-coal coalition left in the UK (Rentier et al, 2019). Aided by a portfolio of policies making coal-fired electricity more expensive – a carbon tax in particular – the coal phase-out was relatively easy and fast (Wilson and Staffel, 2018, Leroutier 2022): between 2012 and 2020, the share of coal in the electricity production dropped from 40 to 2 percent.
In 2011, the Fukushima nuclear catastrophe in Japan triggered an early and unexpected phase-out of nuclear energy in Germany. The 2011 “Energiewende” (energy transition) mandated a phase-out of nuclear power plants by 2022, while including provisions to reduce the share of fossil fuel from over 80 percent in 2011 to 20 percent in 2050. The share of nuclear energy in the electricity production in Germany was halved in a decade, from 22 percent in 2010 to 11 percent in 2020. At the same time, the share of renewable energy increased from 13 to 36 percent, and that of natural gas from 14 to 17 percent.
In these three examples, climate objectives were never the main driver of the decision. Nevertheless, in the case of France and the UK, the crisis resulted in an energy sector that is arguably more low-carbon than it would have been without the crisis. Although the German nuclear phase-out was accompanied by large subsidies to renewable energies, its effect on the energy transition is ambiguous: some argue that the reduction in nuclear electricity production was primarily offset by an increase in coal-fired production (Jarvis et al, 2022).
The three crises also had different consequences in terms of dependence on fossil fuel imports. The French nuclear plan resulted in an arguably lower energy dependency on imported fossil fuels. The closure of coal mines in the UK had ambiguous effects on energy security, with an increase in coal imports and the use of domestic gas from the North Sea. Finally, Germany’s nuclear phase-out, combined with the objective of phasing out coal, has been associated with an increase in the use of fossil fuels from Russia: gas imports remained stable between 2011 and 2020, but the share coming from Russia increased by 60 percent over the period. In 2020, Russia stood for 66 percent of German gas imports (Source: Eurostat). Which brings us back to the current war in Ukraine.
The Current Crisis is Different
The context in which the current energy crisis is unfolding is different from the three above-mentioned events in two important ways.
First, scientific evidence on the relationship between fossil fuel use, CO2 emissions and climate damages has never been clearer: we know quite precisely where the planet is heading if we do not drastically reduce fossil fuel use in the coming decade. From recent research in economics, we also know that price signals work and that increased prices on fossil fuels result in lower demand and emission reductions (Andersson 2019; Colmer et al. 2020; Leroutier 2022). High fuel prices can also have long-term impacts on consumption patterns: US commuters that came of driving age during the oil prices of the 70s, when gasoline prices were high, still drive less today (Severen and van Benthem, 2022). The other way around, low fossil fuel prices have the potential to lock in energy-intensive production: plants that open when electricity and fossil fuel prices are low have been found to consume more energy throughout their lifetime, regardless of current prices (Hawkins-Pierot and Wagner, 2022).
Second, alternatives to fossil fuels have never been cheaper. It is most obvious in the case of electricity production, where technological progress and economies of scale have led to a sharp decrease in the cost of renewable compared to fossil fuel technologies. As shown in Figure 4, between 2010 and 2020 the cost of producing electricity from solar PV has decreased by 85 percent and that of producing electricity from wind by 68 percent. From being the most expensive technologies in 2010, solar PV and wind are now the cheapest. Given the intermittency of these technologies, managing the transition to renewables requires developing electricity storage technologies. Here too, prices are expected to decrease: total installed costs for battery electricity storage systems could decrease by 50 to 60 percent by 2030 according to the International Renewable Agency.
Finding alternatives to fossil fuels has historically been more challenging in the transport sector. However, recent reductions in battery costs, and an increase in the variety of electric vehicles available to customers, have led to EVs taking market share away from gasoline and diesel-powered cars in Europe and elsewhere. The costs of the battery packs that go into electric vehicles have fallen, on average, by 89 percent in real terms from 2010 to 2021.
Figure 4. Evolution of the Mean Levelised Cost of Energy by Technology in the US
Options for Policy-Makers
Faced with a strong increase in fossil fuel prices and an incentive to reduce our reliance on oil and gas from Russia, policy-makers have two options: increase the availability and decrease the price of low-carbon substitutes – by, for example, building more renewable energy capacity and subsidizing electric vehicles – or cut taxes on fossil fuels and increase their supply, both domestically and from other countries.
Governments have pursued both options so far. On the one hand, the Netherlands, the UK, and Italy announced an expansion of wind capacities compared to what was planned, in an attempt to reduce their dependence on Russian gas, and France ended gas heaters subsidies. On the other hand, half of EU member states have cut fuel taxes for a total cost of €9 billion by the end of March 2022, the UK plans to expand oil and gas drilling in the North Sea, and Italy might re-open coal-fired plants.
To guide policymakers faced with the current energy crisis, there are valuable lessons to draw from the experiences of energy policy reform in France, the UK and Germany. France’s push for nuclear energy in the 1970s shows that large-scale structural reform of electricity and heat production is possible and may lead to large drops in CO2 emissions and an economy less dependent on domestic or foreign supplies of fossil fuels. A similar “Messmer plan” could be implemented in the EU today, with the goal of replacing power plants using coal and natural gas with large-scale solar PV parks, wind farms and batteries for storage. Similarly, the German experience shows the potential danger of implementing a policy to alleviate one concern – the risk of nuclear accidents – with the consequence of facing a different concern later on – the dependence on fossil fuel imports.
One additional challenge is that the current energy crisis calls for a short-term response, while investments in low-carbon technologies made today will only deliver in a few years. Short-term energy demand reduction policies can help, on top of long-term energy efficiency measures. For example, a 1°C decrease in the temperature of buildings heated with gas would decrease gas use by 10 billion cubic meters a year in Europe, that is, 7 percent of imports from Russia. Similarly, demand-side policies could reduce oil demand by 6 percent in four months, according to the International Energy Agency.
Ending the reliance on Russian fossil fuels and alleviating energy costs for firms and households is clearly an important objective for policymakers. However, by signing new long-term supply agreements for natural gas and cutting energy taxes, policymakers in the EU may create a carbon lock-in and increase fossil fuel usage by households, thereby making the inevitable low-carbon transition even more difficult. The solutions thus need to take the looming climate crisis into account. For example, any tax relief or increased domestic fossil fuel generation should have a clear time limit; more generally, all policies decided today should be evaluated in terms of their contribution to domestic and European climate objectives. In this way, the current energy crisis is not only a challenge but also a historic opportunity to accelerate the low-carbon transition.
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Since the beginning of the Russia-Ukraine war, the West has been contemplating sanctions on Russian oil and gas imports. For the EU, this plan poses a significant challenge due to the long-existing sizable dependency on Russian energy. In this brief, we outline the possible effects of banning Russian oil and gas on the energy import bill across the EU. While the effects of such a ban will go beyond a direct increase in the import costs of oil and gas, our estimates provide a useful reference point in discussing the impact of such sanctions on the EU. Our estimates suggest that the relative increase in the import costs in the case of an oil embargo would be more evenly spread across the Member States, than in the case of a natural gas ban. This parity makes an EU-wide Russian oil embargo a more straightforward sanction policy. In turn, a full replacement of Russian gas imports across the EU – due to either a gas embargo or retaliation from Russia in response to an oil ban – is likely to require some kind of solidarity mechanism.
Since the beginning of the Russian invasion of Ukraine, the West has been discussing the idea of sanctioning the aggressor by banning Russian energy imports. The motivation is quite straightforward. In 2021, Russian oil and gas exports constituted 49% of Russian goods exports or 14 % of Russian GDP, and the Western world (in particular, the European Union) is the main recipient of these exports. Banning Russian oil and gas export would, thus, lead to heavy pressure on the Russian economy.
The discussion has been quite heated. The US actually implemented a ban on Russian oil and gas in early March 2022, but this gesture has been largely seen as relatively symbolic, as the US dependency on Russian energy imports is quite limited. EU politicians have voiced different opinions about the feasibility of Russian energy sanctions. While some advocate an immediate ban, others argue for a more gradual decrease in imports or even for continuing imports effectively in a business-as-usual fashion. While the EC has announced plans to cut down the consumption of Russian gas by two-thirds in 2022 and mentioned the implementation of “some form of oil embargo” as part of their 6th sanction package, there is still no consensus across the EU. Sanctions on Russian oil and gas imports have not been implemented in the EU by the time of writing this brief.
The main reason for this hesitation is the extent to which Russia remains the main energy supplier. In 2020, 39% of gas and 36% of oil and oil products in the EU were imported from Russia, and the feasibility and consequences of replacing these with alternative supplies are debatable. Since the beginning of the war academics, international organizations and consultancies have offered a variety of analytical materials on the feasibility and implications of such energy sanctions (see e.g., Bachmann et al. 2022. Chepeliev et al, 2022, Fulwood et al., 2022, Guriev and Itskhoki, 2022, Hilgenstock and Ribakova, 2022, IEA, 2022, RYSTAD 2002a,b, Stehn, 2022 to name just a few).
This brief contributes to these estimates by discussing how a Russian oil and gas ban could affect the energy import bill across individual EU countries. We start by providing details on the EU’s dependency on Russian oil and gas imports. We then proceed to access the scope of the costs that a ban on Russian energy could imply for the EU energy sector. We conclude with a discussion about the feasibility of political agreement on such sanctions.
Import Dependency and Dependency on Russian Energy Across the EU
The two primary channels through which a Russian energy ban would affect the vulnerability of an EU country are the dependency on Russian oil and gas, and the overall energy import dependency. The former matters since a ban would imply an immediate necessity to replace missing volumes of energy. This would lead to an increase in energy prices widely across markets, thereby signifying the importance of the latter channel, the overall import dependency.
Figures 1 and 2 depict the dependency on Russian oil and gas across the EU member states. In Figure 1, the dependency is measured as a ratio of Russian energy imports to the gross available energy for each energy type separately – crude oil, oil and oil products, and natural gas. However, this measure may not reflect the importance of the respective energy type in a country’s energy portfolio. For example, in Finland, Russian gas imports constitute 67% of gross available natural gas. However, natural gas is less than 7% of the country’s energy mix, thus the overall effect of Russian gas on the Finnish energy sector and economy is rather limited. To account for this, Figure 2 offers an overview of the contribution of Russian energy imports to the cumulative energy portfolio across the EU.
Both figures show that there is a large variation both in terms of the contribution of individual energy types and in terms of overall dependency on Russian fuels. For example, the latter is almost negligible for Cyprus and well over 50% for Lithuania (however, Figure 2 accounts for re-exports and, thus, overestimates the role of Russian energy imports for Lithuanian domestic available energy in 2020.
Figure 1. Share of Russian energy imports in gross available energy, by fuel, 2020.
Figure 2. Share of Russian energy imports in total gross available energy, 2020. Source: Eurostat
While the above data summarizes the EU dependency on Russian energy imports in volume terms, it is also useful to have a sense of the costs of this dependency. As we are not aware of any source that has accurate data on the value of imports across the EU states, we construct a back-of-the-envelope assessment of the costs of Russian energy imports to the EU in 2021 using the available trade data for 2021 and the allocation of imports across the EU Member States for 2020 (see Appendix 1 for more details). Admittedly, these estimates only account for the differences in prices of energy imports from Russia vs. other suppliers; it does not capture e.g., the difference in prices of Russian gas across the Member States. Still, they offer useful insight into the scope of these expenses, in levels (Figure 3) and the share of GDP (Figure 4).
The results suggest that, while the expenses are quite sizable – e.g., the total value of Russian fossil energy imports to the EU in 2021 exceeds 110 bln EUR, – they correspond to around 0.7% of European GDP. Again, there is variation across the Member States, but in most cases – effectively all cases that do not account for re-export – the share of Russian energy imports is below 2% of GDP.
Figure 3. Value of Russian fossil energy imports, bln EUR, 2021.
Figure 4. Share of oil, oil products and gas imports in GDP, 2021.
Figure 4 also touches upon the second source of vulnerability towards a ban on Russian energy, mentioned at the beginning of this section. It depicts not only the value of Russian oil and gas imports as a percent of GDP but the overall dependency on imports of oil and gas as a share of GDP. The larger this dependency is, the bigger is the impact of an increase in energy prices for a country. Figure 4 not only confirms the abovementioned variation across the Member States but also shows that some countries with little-to-moderate direct dependency on Russian oil and gas – e.g., Portugal or Spain, – are still likely to experience a sizable negative shock to their energy expenses due to the market price increase.
Importantly, these figures give only a very rough representation of the potential damage that a ban on Russian energy imports may cause to the EU economies. Two EU Member States with a comparable dependency could react to the shortage of Russian gas in very different ways, depending on a variety of other factors – the extent and scalability of domestic production, diversification of their remaining energy portfolio in terms of energy suppliers and types of oil the economy relies on (e.g., light vs. heavy), energy infrastructure (e.g., LNG regasification facilities or storage), consumption structure, etc. Le Coq and Paltseva (2009, 2012) discuss in detail some of these factors, and the possibilities to account for them. However, for the sake of simplicity, in this brief we focus on the (volume- and value-based) measures of dependency.
Potential Costs of Russian Energy Import Ban
In this section, we discuss the potential implications of banning imports of Russian oil and gas on the costs of fossil energy imports in the EU. We offer a few historical parallels in order to assess the potential scope of the price reaction to such a ban. Furthermore, we proceed to provide estimates of the costs of oil and gas imports across the EU Member States, would such sanctions be implemented.
Oil Imports Ban
We start with a potential ban on Russian oil and oil product imports. To put things in perspective, it might be useful to present some numbers. According to the IEA, Russia recently surpassed Saudi Arabia as the world’s largest oil and oil products exporter. In December 2021, global Russian crude and oil product exports constituted 7.8 million barrels per day (mb/d), with exports of crude oil and condensate at 5 mb/d. Out of the total 7.8 mb/d, exports to OECD countries constituted 5.6 mb/d, with crude oil exports amounting to 3.9 mb/d. Assuming that the size of the global oil market in 2021 returns to its pre-pandemic 2019 level (the actual data for 2021 global oil consumption is not available yet), Russian crude oil exports to the OECD constitute 8.6% of global crude exports. The corresponding figure for oil products is 6.8% (BP, 2021).
So, what would happen if the developed world – which for the purpose of this analysis we proxy by OECD – bans Russian oil exports? In the recent public discussion, many voices have compared this potential development to the 1973 oil crisis. This crisis was initiated by OAPEC’s – the Arab members of OPEC, – oil embargo on the US in response to their support of Israel during the Yom Kippur War. The OAPEC, the biggest group of oil exporters at the time, completely banned oil exports to the US (and a number of other western countries), and also introduced production restraints that affected the global oil market. The (WTI) oil price during this episode went up by a factor of three (see, e.g, Baumeister and Kilian, 2016).
However, a few important features are likely to differ between the oil crisis of 1973 and the potential impact of the Russian imports ban. First, the net loss of oil supplies during the Arab embargo was around 4.4 mb/d, which at that point constituted around 14% of traded oil (Yergin, 1992). Recall that Russian supplies to OECD are around half of this share. Moreover, it is likely that the ban would not lead to a complete withdrawal of these amounts from the market, but rather to a partial rerouting of Russian oil to Asia and, consequently, a readjustment of world oil trade flows. Second, Yergin (1992) points out that, at the time of the 1973 oil crisis, oil consumption was growing at 7.5% per year, which exacerbated the impact of the embargo. In contrast, the current assessments of oil demand growth are at around 2% per year (IEA, 2022). Third, the energy portfolios are much more diversified now than in 1973, with gas and renewables playing a more substantial role. In the case of an isolated oil imports ban (not extending to gas imports), this would argue in favor of a more moderate price impact. Finally, the oil embargo of 1973 was a never-seen-before episode in the history of the oil market. The uncertainty about future developments has likely contributed to the oil price increase. While there is substantial uncertainty associated with the impact of a Russian oil imports ban, it is arguably lower than in 1973. Based on these considerations, a three-fold oil price increase in the case of a Russian oil export ban seems highly unlikely.
As a possible lower bound of the price impact, one can consider a much more recent price shock brought about by drone attacks on the oil processing facilities Abqaiq and Khurais in Saudi Arabia in 2019. In the initial assessment of the damage, Saudi Arabian authorities stated that the attack decreased the national oil production by 5.7 mb/d – which is more than the total of Russian oil exports to OECD. As a reaction, the intraday oil price went up by 20 %, and the daily oil price by 12%. In two weeks, production and export capacity was almost back to normal and the price returned to pre-shock levels.
Notice that the scale of the daily shortage in this episode exceeds the likely shortage under the Russian imports ban. However, a moderate price reaction, in this case, was clearly driven by expectations for the temporary nature of the shortage, as the damage was to be repaired in a matter of a few weeks, if not days. In comparison, the Russian oil ban is likely to last much longer. In this way, a price increase of 12%, or even 20%, would be an underestimation of the effect of a Russian oil imports ban.
While the above discussion suggests some bounds for the possible price effects of a Russian oil ban, the uncertainty around such price developments is very high. Figure 5 shows the cost estimates of oil and oil products imports to the EU for two potential price levels – $120/b, and $180/b. Each price would roughly correspond to an increase of 33%, and 100%, respectively, relative to the pre-invasion price of $90/b. In the estimation, we simplistically assume that the price of oil products increases by the same amount as the price of crude oil. We also assume that the missing Russian oil can be replaced by alternatives, such that oil consumption does not change compared to the 2021 level for the lower price scenario and that it decreases by 2% for the high-cost scenario due to the demand adjustments.
Figure 5. Estimated effect of Russian oil ban on oil and gas imports in 2022: value of oil and oil products imports, EUR bln (left axis), and oil import expenses relative to 2021 level (right axis).
The estimates suggest that the total oil and oil products import costs for the EU would be just above EUR 640 bln for the $120/b price level and EUR 940 bln for the $180/b price level. Furthermore, the costs across the EU Member States would vary greatly depending on the size of the economy and its exposure to oil imports.
This shows that – provided that the Russian oil will be fully replaced but at a higher price – the expected cost of this is in the range of 1.7-1.9 times the 2021 expenses at 120$/b, and 2.5-2.8 times that if the price would be 180$/b. While there is some variation across Member States, mostly driven by the removal of the somewhat cheaper Russian oil from the consumption basket, it is rather limited. Figure 5 also demonstrates that the ban on Russian oil imports is going to affect not only countries that directly depend on Russian oil but also countries with large oil and oil products imports due to the market price effects.
Gas Imports Ban
Now we proceed to discuss the costs of banning Russian gas imports into the EU. While LNG has increased the fungibility of the natural gas market, it remains sizably segmented. Therefore, we concentrate on the effect on the European market.
Russian gas constituted around 39% of the EU gas consumption volumes in 2020, and just below 30% in 2021 due to restricted supply during the second half of the year (McWilliams, Sgaravatti and Zachmann, 2021). It is currently a common understanding that fully substituting 155 Bcm of Russian gas imports in 2021 with imports from other pipeline suppliers, LNG, storage, and increasing domestic production is not feasible in 2022. Different sources have given different estimates on the extent of the resulting shortage, see e.g. Table 1.
Table 1. Alternatives to replace EU imports of Russian natural gas
As shown in Table 1, the net missing gas consumption ranges between 12% and 22% across different scenarios. As there are no historical episodes in the gas market to which such a development can be compared, it is difficult to assess the potential price reaction. One rough comparison can be made based on the oil market situation during the Arab oil embargo of 1973 discussed above. Then, the net loss of oil constituted about 9% of the oil consumption in “the free world” (Yergin, 1982), even lower than the most optimistic prognosis in Table 1. However, 33 Mcb of Russian gas (or 6% of 2021 the EU’s gas consumption) has already been imported to the EU since the beginning of 2022, making the potential gas shortage quite comparable to the oil shortage of 1973. Subject to all differences between the two shocks, one can, perhaps, still argue that the gas price increase following a ban on Russian gas imports should not exceed three-fold from before the invasion.
It is important to stress here that the EU gas market situation in the case of the Russian gas embargo would be principally different from the oil market one. Due to supply shortage not coverable by the alternative gas sources, a gas embargo would lead not only to a stronger price increase than in the case of oil, but also to significant downward demand adjustments, rationing and, perhaps, even price controls. (This, again, parallels the developments during the 1973 oil crisis). The negative effect of such rationing is not accounted for by the import bill. On the contrary, a shortage of supply would imply lower gas import volumes, biasing the impact on the gas import bill downward. In this way, an import bill reaction to sanctions in the case of natural gas may more strongly underestimate the overall impact on the economy than in the case of oil.
While the above argument suggests a higher price increase in the case of a gas embargo in comparison to an oil ban, there is still a lot of uncertainty in forecasting the gas price. Figure 6 depicts the estimates for the natural gas cost across the EU for two potential price levels – EUR 160/Mwh, and EUR 240/Mwh, a two- and three-fold increase relative to the pre-invasion price level of EUR 80/Mwh. Both estimates assume a (moderate) 8% decrease in the demand reflecting the abovementioned supply shortage and demand adjustments. We assume that the shortage is affecting both the importers of Russian gas and those who use other suppliers due to the common gas market in the EU and the use of reverse flow technology – as was the case for Poland which was denied Russian gas on April 27th, 2022 due to not paying for it in Rubles (see Appendix 1 for a discussion of implications of this assumption).
Not surprisingly, the gas import costs increase drastically in comparison to 2021. The total figures for the EU would be just below EUR 680 bln in the two-fold price increase scenario, and exceed 1 trn EUR in the case of a three-fold increase, in contrast to EUR 185 bln in 2021. Again, the largest economies bear the highest costs in absolute value.
When it comes to the relative increase in gas import value, two further observations follow from Figure 6. First, there is a huge variation in the increase in the value of gas imports across the Member States, from no effect in Cyprus which does not import natural gas, to 7.7 times in the case of a price doubling and 11.5 times in the case of a price tripling. Again, this variation originates from the necessity to replace cheaper Russian gas with more expensive gas sources, and the effect is much stronger than for oil. However, just like in the oil case, the states not directly importing Russian gas will still experience a huge negative shock from such a price hike. (Recall also, that the variation of the impact across the Member States is likely underestimated here, as the gas bill does not account for potential rationing which may differentially impact the importers of Russian gas).
Second, the increase in the value of gas imports exceeds the scale of the price increase even for the least affected Member States (excluding Cyprus). This is due to the unprecedented gas price increase during the EU gas crisis that took place between late 2021 and the beginning of 2022. Due to this increase, the pre-invasion gas price in February 2022 was 60% higher than the average gas price in 2021.
Figure 6. Estimated effect of Russian natural gas ban on gas imports in 2022: value of gas imports, EUR bln (left axis), and gas import expenses relative to 2021 level (right axis).
The above estimates suggest that a ban on Russian oil and gas imports is going to be costly for the EU. While uncertainty is very high concerning the possible energy price increase following such a ban, historical parallels together with the market characteristics suggest that both the price increase and the rise in the value of imports are going to be stronger for natural gas. The resulting increase in the EU-wide import values relative to 2021 ranges from 1.8 to 2.6 times for the considered oil scenarios, and from 3.7 to 5.5 times for the natural gas scenarios.
Unsurprisingly, the most sizable import costs will be faced by the larger EU Member States, as well as those most dependent on oil and gas imports. However, all EU countries are going to be affected due to the market price increase. While the relative rise in the import costs of oil and oil products will be fairly uniformly met across the EU states, the increase in the costs of gas exports will vary greatly, with the largest relative losses faced by the EU states that are currently more exposed to Russian gas imports.
The above figures provide a rough assessment of the potential costs of a Russian fossil fuels ban. The approach does not take into account substitutability between different fuels and resulting cross-effects on prices, which implies that the costs could be both under- and overestimated. It has a very limited and simplistic take on the demand reaction to a price increase, which again may lead to either over- or underestimation of the effect. Neither does it account for the consequences of such price increases on the costs of electricity and implications for the non-energy sector within the economies. The latter may, again, be differentially affected depending on the industrial composition and their relative energy intensity. Another factor to consider is the interconnectivity between the EU economies – for example, an increase in Germany’s energy bill is likely to have a large impact on the entire EU. Moreover, the use of the import bill as a proxy for the overall effect on the economy may have further limitations in the case of supply shortage and rationing. To provide a more precise estimate of the impact of such a ban on the entire economy, for instance on GDP, one would require an extensive and sophisticated model along the lines of the CGE approach, relying on large amounts of data (Bachmann et al. (2022) provide an excellent example of such a study of the effect on Germany). This, however, is beyond the scope of the current assessment.
Still, even this relatively simplistic assessment of import costs of a Russian energy ban offers sufficient food for thought for the discussion of the scale of damage across the EU Member States and the feasibility of oil and gas sanctions. For example, the assessment suggests that an oil ban is likely to yield relative parity across the Member States in terms of the increase in the 2022 oil import bill as compared to the 2021 level. This would imply that, were the EU to decide on a gradual sanctioning of Russian oil and gas, it would be easier to reach an EU-wide agreement on oil sanctions. In turn, moving away from Russian gas – due to either the decision to ban gas imports or retaliation from Russia in response to oil sanctions, -implies very uneven import cost exposure. Thus, to face the challenge of replacing Russian gas imports, the EU would likely need to implement some kind of energy solidarity mechanism.
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The recent record-high gas prices have triggered legitimate concerns regarding the EU’s energy security, especially with dependence on natural gas from Russia. This brief discusses the historical and current risks associated with Russian gas imports. We argue that decreasing the reliance on Russian gas may not be feasible in the short-to-mid-run, especially with the EU’s goals of green transition and the electrification of the economy. To ensure the security of natural gas supply from Russia, the EU has to adopt the (long-proclaimed) coordinated energy policy strategy.
In the last six months, Europe has been hit by a natural gas crisis with a severe surge in prices. Politicians, industry representatives, and end-energy users voiced their discontent after a more than seven-fold price increase between May and December 2021 (see Figure 1). Even if gas prices somewhat stabilized this month (partly due to unusually warm weather), today, gas is four times as expensive as it was a year ago. This has already translated into an increase in electricity prices, and as a result, is also likely to have dramatic consequences for the cost and price of manufacturing goods.
Figure 1. Evolution of EU gas prices since Oct 2020.
These ever-high gas prices have triggered legitimate concerns regarding the security of gas supply to Europe, specifically, driven by the dependency on Russian gas imports. Around 90% of EU natural gas is imported from outside the EU, and Russia is the largest supplier. In 2020, Russia provided nearly 44% of all EU gas imports, more than twice the second-largest supplier, Norway (19.9%, see Eurostat). The concern about Russian gas dependency was exacerbated by the new underwater gas route project connecting Russia and the EU – Nord Stream 2. The opponents to this new route argued that it will not only increase the EU’s gas dependency but also Russia’s political influence in the EU and its bargaining power against Ukraine (see, e.g., FT). Former President of the European Council Donald Tusk stated that “from the perspective of EU interests, Nord Stream 2 is a bad project.”.
However, neither dependency nor controversial gas route projects are a new phenomenon, and the EU has implemented some measures to tackle these issues in the past. This brief looks at the current security of Russian gas supply through the lens of these historical developments. We provide a snapshot of the risks associated with Russian gas imports faced by the EU a decade ago. We then discuss whether different factors affecting the EU gas supply security have changed since (and to which extent it may have contributed to the current situation) and if decreasing dependence on Russian gas is feasible and cost-effective. We conclude by addressing the policy implications.
Security of Russian Gas Supply to the EU, an Old Problem Difficult to Tackle
Russia has been the main gas provider to the EU for a few decades, and for a while, this dependency has triggered concerns about gas supply security (see, e.g., Stern, 2002 or Lewis, New York Times, 1982). However, the problem with the security of Russian gas supplies was extending beyond the dependency on Russian gas per se. It was driven by a range of risk factors such as insufficient diversification of gas suppliers, low fungibility of natural gas supplies with a prevalence of pipeline gas delivery, or use of gas exports/transit as means to solve geopolitical problems.
This last point became especially prominent in the mid-to-late-2000s, during the “gas wars” between Russia and the gas transit countries Ukraine and Belarus. These wars led to shortages and even a complete halt of Russian gas delivery to some EU countries, showing how weak the security of the Russian gas supply to the EU was at that time.
Reacting to these “gas wars”, the EU attempted to tackle the issue with a revival of the “common energy policy” based on the “solidarity” and “speaking in one voice” principles. The EU wanted to adopt a “coherent approach in the energy relations with third countries and an internal coordination so that the EU and its Member States act together” (see, e.g., EC, 2011). However, this idea turned out to be challenging to implement, primarily because of one crucial contributor to the problem with the security of Russian gas supply – the sizable disbalance in Russian gas supply risk among the individual EU Member States.
Indeed, EU Member States had a different share of natural gas in their total energy consumption, highly uneven diversification of gas suppliers, and varying exposure to Russian gas. Several Eastern-European EU states (such as Bulgaria, Estonia, or Czech Republic) were importing their gas almost entirely from Russia; other EU Member States (such as Germany, Italy, or Belgium) had a diversified gas import portfolio; and a few EU states (e.g., Spain or Portugal) were not consuming any Russian gas at all. Russian natural gas was delivered via several routes (see Figure 2), and member states were using different transit routes and facing different transit-associated risks. These differences naturally led to misalignment of energy policy preferences across EU states, creating policy tensions and making it difficult to implement a common energy policy with “speaking in one voice” (see more on this issue in Le Coq and Paltseva, 2009 and 2012).
Figure 2. Gas pipeline in Europe.
The introduction of Nord Stream 1 in 2011 is an excellent example of the problem’s complexity. This new gas transit route from Russia increased the reliability of Russian gas supply for EU countries connected to this route (like Germany or France), as they were able to better diversify the transit of their imports from Russia and be less exposed to transit risks. The “Nord Stream” countries (i.e., countries connected to this route) were then willing to push politically and economically for this new project. Le Coq and Paltseva (2012) show, however, that countries unconnected to this new route while simultaneously sharing existing, “older” routes with “Nord Stream” countries would experience a decrease in their gas supply security. The reason for this is that the “directly connected” countries would now be less interested in exerting “common” political pressure to secure gas supplies along the “old” routes.
This is not to say that the EU did not learn from the above lessons. While the “speaking in one voice” energy policy initiative was not entirely successful, the EU has implemented a range of actions to cope with the risks of the security of gas supply from Russia. The next section explains how the situation is has changed since, outlining both the progress made by the EU and the newly arising risk factors.
Security of Russian Gas Supply to the EU, a Current Problem Partially Addressed
Since the end of the 2000s, the EU implemented a few changes that have positively affected the security of gas supply from Russia.
First, the EU put a significant effort into developing the internal gas market, altering both the physical infrastructure and the gas market organization. The EU updated and extended the internal gas network and introduced the wide-scale possibility of utilizing reverse flow, effectively allowing gas pipelines to be bi- rather than uni-directional. These actions improved the gas interconnections between the EU states (and other countries), thereby making potential disruptions along a particular gas transit route less damaging and diminishing the asymmetry of exposure to route-specific gas transit risks among the EU members. Ukraine’s gas import situation is a good illustration of the effect of reverse flow. Ukraine does not directly import Russian gas since 2016, mainly from Slovakia (64%), Hungary (26%), and Poland (10%) (see https://www.enerdata.net/publications/daily-energy-news/ukraine-launches-virtual-gas-reverse-flow-slovakia.html). The transformation of the gas market organization brought about the implementation of a natural gas hub in Europe and change in the mechanism of gas price formation. It is now possible to buy and sell natural gas via long-term contracts and on the spot market. With the gas market becoming more liquid, it became easier to prevent the gas supply disruption threat.
Second, Europe has made certain progress in diversifying its gas exports. According to Komlev (2021), the concentration of EU gas imports from outside of the EU (excluding Norway), as measured by the Herfindahl-Hirschman index, has decreased by around 25% between 2016 and 2020. While the imports are still highly concentrated, with the HHI equal to 3120 in 2020, this is a significant achievement. A large part of this diversification effort is the dramatic increase in the share of liquified natural gas (i.e., LNG) in its gas imports – in 2020, a fair quarter of the EU gas imports came in the form of LNG. An expanded capacity for LNG liquefaction and better fungibility of LNG would facilitate backup opportunities in the case of Russian gas supply risks and improve the diversification of the EU gas imports, thereby increasing the security of natural gas supply.
However, the above developments also have certain disadvantages, which became especially prominent during the ongoing gas crisis. For example, the fungibility of LNG has a reverse side: LNG supplies respond to variations in gas market prices across the world. This change has intensified the competition on the demand side – Europe and Asia might now compete for the same LNG. This is likely to make a secure supply of LNG – e.g., as a backup in the case of a gas supply default or as a diversification device – a costly option.
In turn, new mechanisms of gas price formation in Europe included decoupling the oil and gas prices and changing the format of long-term gas contracts. The percentage of oil-linked contracts in gas imports to the EU dropped from 47% in 2016 to 26% in 2020. In particular, 87% of Gazprom’s long-term contracts in 2020 were linked to spot and forward gas prices and only around 13% to oil prices (Komlev, 2021). This gas-on-gas linking may have contributed to the current gas crisis: Indeed, it undermined the economic incentives of Gazprom to supply more gas to the EU spot market in the current high-price market. Shipping more gas would lower spot prices and prices of hub-linked longer-term contracts for Gazprom. In that sense, the ongoing decline in Russian gas supplies to the EU may reflect not (only) geopolitical considerations but economic optimization.
Similarly, this new mechanism also finds reflection in the ongoing situation with the EU gas storage. The current EU storage capacity is 117 bcm, or almost 20% of its yearly consumption, and thus, can in principle be effective in managing the short-term volume and price shocks. However, the current gas crisis has shown that this option might be far from sufficient in the case of a gas shortage (see, e.g., Zachmann et al., 2021). One of the reasons for this insufficiency can be Gazprom controlling a sizable share of this storage capacity (see https://www.europarl.europa.eu/doceo/document/E-9-2021-004781_EN.html). For example, Gazprom owns (directly and indirectly) almost one-third of all gas storage in Germany, Austria, and the Netherlands. Combining this storage market position with a long-term gas contract structure may also lead to strategic behavior for economic (on top of potential political) purposes.
Last but not least, the EU gas market is likely to be characterized by increased demand due to the green transition agenda (see Olofsgård and Strömberg, 2022). Being the least carbon-intensive fossil fuel, natural gas has an important role in facilitating green transition and increasing the electrification of the economy. For example, Le Coq et al. (2018) argues that gas capacity should be around 3 to 4 times the current capacity by 2050 for full electrification of transport and heating in France, Germany, or the Netherlands. In such circumstances, the EU is not likely to have the luxury to diminish reliance on Russian gas.
Conclusions and Policy Implications
Keeping the above discussion in mind, should the EU try to diminish its dependence on Russian gas to improve its energy security? This may be true in theory, but in practice, this might be too costly, at least in the short-to-medium run.
The current situation on the EU gas market suggests that simply cutting gas imports from Russia is likely to lead to high prices both in the energy sector and, later, in other sectors of the economy due to spillovers. Substituting gas imports from Russia with gas from other sources, such as LNG, is likely to be very costly and not necessarily very reliable. Alternative measures, e.g., improving interconnections between the EU Member States or controlling transit issues via the use of reverse flow technology, are effective but have limited impact. Simply cutting down gas demand is not a viable strategy. Indeed, with the EU pushing for a green transition and the electrification of the economy, the EU’s gas imports may have to increase. Russian gas may play an important role in this process.
As a result, we believe that the solution to keep the security issue of Russian gas supply at bay lies in the area of common energy policy. It is essential that the EU implements and effectively manages a coordinated approach in dealing with Russian gas supplies. The EU is the largest buyer of Russian gas, and given Russian dependency on hydrocarbon exports, such a synchronized approach would give the EU the possibility to exploit its “large buyer” power. While the asymmetry in exposure to Russian gas supply risks among the EU Member States is still sizable, the improvements in the functioning of the internal gas market and gas transportation within the EU make their preferences more aligned, and a common policy vector more feasible. Furthermore, recent EU initiatives on creating “strategic gas reserves” by making the Member States share their gas storage with one another would further facilitate such coordination. Implementing the “speaking in one voice” gas import policy will allow the EU to fully utilize its bargaining power vis-à-vis Gazprom and spread the benefits of new gas routes from Russia – such as Nord Stream 2 – across its Member States.
- European Commission, 2011, “Speaking with one voice – the key to securing our energy interests abroad“, press release, https://ec.europa.eu/commission/presscorner/detail/en/IP_11_1005
- Komlev, S. 2021, “Evolution of Russian Gas Supple to Europe: Contracts and Prices”, Presentation at 34th WS2 GAC, https://minenergo.gov.ru/system/download/14146/158148
- Le Coq C. and E. Paltseva (2020), Covid-19: News for Europe’s Energy Security, FREE Policy brief. https://freepolicybriefs.org/2020/05/07/covid-19-energy-security-europe/
- Le Coq C., J. Morega, M. Mulder, S Schwenen (2018) Gas and the electrification of heating & transport: scenarios for 2050, CERRE report.
- Le Coq C. and E. Paltseva (2013) EU and Russia Gas Relationship at a Crossroads, in Russian Energy and Security up to 2030, Oxenstierna and Tynkkynen (Eds), Routledge.
- Le Coq C. and E. Paltseva (2012) Assessing Gas Transit Risks: Russia vs. the EU, Energy Policy (4).
- Le Coq C. and E. Paltseva (2009) Measuring the Security of External Energy Supply in the European Union, Energy Policy (37).
- Lewis, Paul, “Gas pipeline is producing lots of steam among allies“, New York Times, Feb. 14, 1982, https://www.nytimes.com/1982/02/14/weekinreview/gas-pipeline-is-producing-lots-of-steam-among-allies.html
- Olofsgård A., and S. Strömberg (2022) Environmental Policy in Eastern Europe | SITE Development Day 202, FREE Policy Brief, https://freepolicybriefs.org/2022/01/10/environmental-policy-in-eastern-europe-site-development-day-2021/
- Stern, J., 2002. Security of European Natural Gas Supplies—The Impact of Import Dependence and Liberalization, Royal Institute of International Affairs, available at: 〈http://www.chathamhouse.org.uk/files/3035_sec_of_euro_gas_jul02.pdf〉
- Zachmann, G., B. McWilliams and G.Sgaravatti, 2021, How serious is Europe’s natural gas storage shortfall? https://www.bruegel.org/2021/12/how-serious-is-europes-natural-gas-storage-shortfall/
While there has been a lot of attention on the effect of Covid-19-related developments in the oil market, the effect on the natural gas market has almost evaded media attention. For the EU, however, the gas market and especially the impact of the pandemic on the gas relationship with its largest gas supplier, Russia, is of high relevance. This brief discusses the potential implications of Covid-19 on this relationship both under the pandemic and during the expected slow economic recovery. We argue that, while in the short run the security of Russian gas supply is likely to improve, this is unlikely to be the case in the aftermath of the pandemic. To ensure gas supply security in post-pandemic markets, the EU may need to finally implement the long-awaited “speaking with one-voice” energy policy.
The ongoing coronavirus pandemic will not only affect human lives, but also bring new economic and political challenges. The energy sector, and in particular the dramatic decrease of oil prices, has been in the news since the beginning of the Covid-19 crisis. But discussions have so far rarely touched the natural gas market, despite the pandemic taking its toll also on this market. As for oil, the demand and price have been negatively affected by the economic slowdown. While not as drastic as for oil, the price of natural gas in the EU has declined by approximately 40% since the beginning of 2020 (World Bank, 2020). However, the impact of the pandemic is likely to be quite different in oil and gas markets. There are multiple reasons for that; for example, oil and oil products are predominantly consumed by the transport sector while natural gas is mostly used in the power sector, the industry and households, and these sectors were differently affected by the Covid-19 pandemic.
Understanding the impact of the pandemic on the gas market is especially interesting from the European point of view, given that natural gas accounts for 25% of total energy consumption and two thirds of this gas is imported. The imports are also very concentrated, with the main supplier Russia providing around 40% of the gas, compared to 25% of the crude oil. This dependency, as well as a long history of tensions with third parties (Ukraine and Belarus) on the Russian gas transit routes, has made the EU’s concerns about the security of Russian gas supply much more pronounced than for oil (see Le Coq and Paltseva, 2012). The combination of these factors – i.e. the importance of natural gas for the EU and the long-standing concern about gas supply security warrant an analysis of the short and mid-term effect of the Covid-19 pandemic on the gas market, and, specifically, on the EU-Russia gas relationship. This brief discusses how the pandemic-driven decline in gas demand, and the potential shift in the balance of power between the parties may affect both the dependency on, and the transit of, Russian gas.
EU Dependency on Russian Gas Under the Covid-19 Pandemic
As is well known, Covid-19 and the associated lockdowns imposed by many EU Member States, have caused a slowdown in most economies and a decline in energy demand. However, for natural gas, the effect is likely to be significantly smaller than for oil. While we do not yet have statistics for the EU’s gas demand in recent months, the Norwegian energy consultancy Rystad Energy has predicted the decline of gas demand to be around 4% for March and April 2020. This forecast was given quite early in the course of the pandemic, and is very likely an underestimation; still, it is very different from the one for oil, with the demand drop estimated to be a whopping 34% in April.
One reason why we do not observe a sizable decrease in gas demand is that the natural gas is used in electricity generation, especially as a base-load fuel to compensate for the intermittency of green energy sources, such as sun and wind. With the reduced electricity demand, renewable power generation has become relatively more important in the electricity supply in many countries. Since mid-March 2020, the share of renewable power generation across the EU is 46%, nine percent higher than during the same period last year (Energy Transition Lab, 2020). Interestingly, in France, Germany, Belgium, the Netherlands, the Czech Republic, Poland and Hungary, the absolute volume of electricity generation by renewable sources even increased relative to the same period in 2019, despite declining energy demand. One potential channel, anecdotally recorded for Germany could be higher solar generation due to cleaner skies resulting from the decline in emissions because of lower fossil energy consumption. A higher volume of a renewable generation often requires more back-up power to maintain grid stability. While natural gas is not the only back-up source, this need might still limit the decline in gas demand (or even increase it like e.g. in the Czech Republic). Of course, cheaper gas prices may also play a role: for example, Slovakia and Romania experienced an increase in gas-based generation, but a drop in the renewable generation since mid-March 2020 relative to the same period in 2019. Finally, another reason for the moderate gas demand decline is its residential use – which is likely to be sustained due to the lockdown regime introduced by many countries.
When it comes to Russian gas imports, the official statistics since mid-March – roughly the beginning of lockdown policies across the EU – are not available yet. However, we can with some reservation look at the evolution of the volume of gas sales to the EU disclosed by Gazprom (2020). There was a very sizable decrease in Russian gas imports by the EU – of more than 21% – as compared to the same period last year but it started before the lockdown: January 2020 recorded a drop of 34% and February of 20%). This suggests that the current decrease in Russian gas imports is only marginally related to the pandemic, and more related to the overall gas market situation (such as relatively full gas storage in the EU in 2020, a warm winter, an increase in LNG imports, etc.).
It is, however, likely that the negative effect of the pandemic on Russian gas imports by the EU will be noticeably higher than it currently appears in the Gazprom data, thereby further decreasing the EU’s dependency on Russian gas. Moreover, since demand and prices decrease, substituting for Russian gas, were there a supply interruption, should be relatively easy and cheap with the current excess capacity of the natural gas market and the substantial storage in the EU.
Another reason for the improvement in the security of Russian gas supply to the EU is the observation that Russia’s dependency on oil and gas exports in combination with pandemic-associated factors may lead to a substantial economic downturn in Russia (Becker, 2020). In these dire circumstances, Russia is unlikely to further risk its gas export revenues by pursuing geopolitical goals through the means of gas supply and gas transit. For all these reasons, one may expect the security of Russian gas supply to the EU to improve during the pandemic.
However, the EU dependency on Russian gas may still be a concern due to medium-run effects of Covid-19. First of all, while the gas prices have been in decline for roughly a year now, the recent decrease in natural gas prices has accelerated the negative impact on the unconventional natural gas industry. For example, the US natural gas rig count has declined by 20% since mid-March 2020, which accounts for more than a third of the 54% year-to-year decline (Ycharts.com, 2020). Similarly, nearly 42% of Australian gas resources could be uneconomic under the current gas prices, according to Rystad Energy. While gas prices are unlikely to stay low forever, the industry will need time to recover even if/when the natural gas demand rises again. Moreover, the East-Asian markets are likely to be served first, as they are expected to recover from the pandemic shock before Europe. This dynamic, coupled with historically higher LNG prices in Asia may delay the LNG flows to Europe. A shortage of LNG in Europe, in turn, is likely to hinder any diversification strategy from Russian gas, weakening the EU’s bargaining power. The new Russia-China gas pipeline, “Power of Siberia”, operational since the end of 2019, will also be used to satisfy the post-Covid-19 Chinese gas demand which is likely to recover before demand picks up in the EU. Its use will then allow Russia to be less reliant on exporting gas to the EU, further contributing to the EU’s gas security concerns.
Transit of Russian Gas to the EU: Covid-19 Effect
The EU’s energy security also depends on the reliability of Russian gas transit to the EU. There are currently 5 transit routes connecting Russia to the EU (plus the routes that are serving the Baltic states and Finland without further transit), see Figure 1. Three onshore routes connect Russia to the EU via Ukraine and Belarus. There has been a history of gas transit disputes associated with these routes, at times threatening the Russian gas supply to the EU. Two newer offshore pipelines, Nord Stream 1 (in operation since 2011) and TurkStream (in operation since 2020) connect Russia directly to Germany, and to the South-East of Europe via Turkey. Further, one more offshore route to Germany, Nord Stream 2, is currently underway, with the operations announced to start in the first quarter of 2021. All three offshore projects are expected to not suffer from geopolitical transit issues.
In relation to the Covid-19 pandemic, there are likely to be two major effects on Russian gas transit. First, the inauguration of Nord Stream 2 is likely to be further delayed. Nord Stream 2 is 50% financed by Gazprom, and this financing scheme may be difficult to sustain after the fall in oil and gas prices and a significant decrease of Gazprom’s export revenues. Indeed, while the statistics for March and April 2020 are not yet available, the Russian customs statistics suggests that the USD value of gas exports from Russia in January-February 2020 has decreased by 45% relative to the same period last year. Because Nord Stream 2 could facilitate gas delivery to the EU in case of a transit conflicts, its expected delay may negatively impact the EU’s gas security.
Additionally, the Covid-19 related demand drop may impact the utilization of Russia-EU gas routes, driven by the current agreements between Russia and the transit countries. Russia and Ukraine have just signed a transit agreement for the next 5 years. This agreement was widely perceived as a diplomatic success of the EU (that facilitated the deal), given the historically difficult geopolitical relation between Ukraine and Russia. One of the new features of this agreement is of particular interest within the Covid-19 context. Unlike for previous deals, Russia agreed to prepay a fixed volume of gas transit, 178.1 mcm/day for 2020, and 110 mcm/day units for 2021-24 (Pirani et al., 2020). So, underutilization of this route is costly for Russia.
Figure 1. Gas supply Routes to the EU.
With decreased demand due to Covid-19, warmer weather in the coming months and almost full gas storages in the EU, this contractual feature may affect how Russia allocates its gas exports across the routes. At least, in the short term, it may undermine Russian gas transit via the Belarus-Poland route. The concern about the utilization of this route in relation to the new Russia-Ukraine transit agreement has already been raised by Pirani et al. (2020). The Covid-19-associated decrease in gas demand is likely to make this concern much more real. Russia may use the Belarus-Poland pipeline sporadically, e.g. to adjust for the seasonal spikes in demand, without long-term capacity booking. Recent gas tensions between Russia and Poland (e.g. Poland winning in the arbitration court against Gazprom (RFE/RL, 2020), and Poland repeatedly expressing opinions and exercising legislative effort restricting the usage of Nord Stream 1 and construction of Nord Stream 2) may further exacerbate the issue.
In the medium term, however, when the EU gas demand has recovered but Nord Stream 2 is not yet in place, the Belarus-Poland route is likely to prove useful for Russia, at least starting from 2021 (when prepaid volumes of Russian gas transit via Ukraine will decline according to their agreement).
The transit contract between Russia and Poland is to be renewed in mid-May 2020, and as of now, it is unclear if, and how it will be written and whether the Belarus-Poland transit route will be used to a substantial degree or only marginally. If transit through the Belarus-Poland route is limited, it will imply poorer route diversification for a major part of European consumers of Russian gas, thereby lowering their security of Russian gas supply. This may also put another strain on the bargaining power allocation within the EU and the EU’s intended common energy policy of “speaking with one voice” with external energy suppliers like Russia.
Summing up, the decrease in demand of natural gas, as well as other factors associated with the ongoing Covid-19 pandemic, such as economic recession and turbulence in stock markets, are likely to have noticeable implications for the security of Russian gas supplies to the EU in the short term. On the one hand, even if the current pandemic-associated decrease in demand of gas from Russia seems rather moderate, the ultimate negative effect on Russian gas imports by the EU is likely to be larger. Lower imports from Russia are likely to improve the security of supply, both through lower import dependency of the EU, and through improved market opportunities due to the current market’s overcapacity. On the other hand, in the medium run, lower demand also negatively affects the non-conventional gas industry, undermining the diversification opportunities to LNG, and, consequently, natural gas energy security. Further, a fall in the gas demand by the EU coupled with the newly signed transit agreement between Russia and Ukraine may potentially cause underusage of the Belarus-Poland transit route, thereby putting a strain on the diversification of Russian gas import routes to the EU and on the power balance within the EU.
Energy security might be even more of a concern in the post coronavirus period when the economy is slowly recovering, and cheap and guaranteed energy supply is crucial. To ensure this supply, national efforts combined with an EU-wide policy coordination would be required. The long-discussed “speaking with one voice” common energy policy may finally need to materialize in order to facilitate reliable access to natural gas.
- Becker, Torbjörn, 2020. “Russia Economic Update — Brace for the Covid-19 Impact!”, FREE Policy Brief.
- Energy Transition Lab, Wärtsilä, 2020, retrieved April 27, 2020
- Gazprom, 2020. REMIT RSS, retrieved April 26, 2020.
- Le Coq, Chloé and Elena Paltseva, 2012. “Buyer Power as a Tool for EU Energy Security”, FREE Policy Brief.
- Pirani, Simon; Jack Sharples, Katja Yafimava, Vitaly Yermakov, 2020. “Implications of the Russia-Ukraine gas transit deal for alternative pipeline routes and the Ukrainian and European markets”, Oxford Institute for Energy Studies.
- World Bank, 2020. “Commodity Price Data (The Pink Sheet)”, retrieved April 26, 2020.
- Ycharts.com, 2020. “US Natural Gas Rig Count: 85.00 for Wk of Apr 24 2020”, retrieved April 27, 2020.
This policy brief summarizes the discussion at the 8th annual SITE Energy Day conference, devoted to market adaptations and policies necessary to address the green transition. Recent energy trends with ever more green energy-mixes will have consequences for the functioning of related markets as well as implications for appropriate policy responses. New financial solutions, technological developments, international cooperation, and national policy initiatives in both developing and developed countries are examples of adaptations to this transition process. To discuss these issues, the conference brought together a group of distinguished experts from the energy industry, policy community and academia.
In December 2014, world leaders have gathered in Peru (Lima) for the 20th annual meeting of the United Nations Framework Convention on Climate Change. This convention has as an objective to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system” (see UNFCCC’s webpage). Even though the agreement to reduce emissions to a sustainable level may take years to be negotiated, at least 195 countries have ratified the UFCCC convention. The willingness to reduce environmentally harmful emissions has led to many countries changing their energy profile to include more green energy, a process that is often referred to as “green transition”.
It may be worth mentioning that the label “green transition” consists of two conceptual components. “Green” refers to the ability to generate environmentally friendly energy, which has become a key challenge for our society. Indeed, a majority of people now recognize the pressing need to cut pollution in the face of climate change and environmental degradation. The wording “transition” acknowledges that a shift toward a greener energy mix seems unavoidable, but this shift may not occur immediately or uniformly around the globe. The required time for change is long and the shift itself may not be smooth. To put it differently, the green transition has had and will continue to have wide-ranging consequences for businesses, governments, and the international community.
As a result, there is a need to carefully address the potential implications for the existing energy and related markets and market players, and for government policies, as well as new markets and new policies triggered by the green transition. These topics were the focus of the 8th SITE Energy Day, a half-day conference held at the Stockholm School of Economics on December 2, 2014.
Green Transition and the Energy Markets
The first panel focused on how energy markets have responded to green transition and how they may react in the future. Speakers from electricity companies, regulatory bodies and think tanks discussed how the green transition may affect the use of traditional financial instruments by energy companies; the choice of economically viable technology for producing green energy; and the way markets could be integrated to increase the efficiency of green energy.
As green transition almost always introduces more intermittent production, it is likely that market uncertainty will increase. This is one of the reasons why traditional financial instruments may not be fully adequate. The first speaker Laurent Cheval, Head of Nordic and Fuel Origination in the business division Asset Optimization & Trading at Vattenfall discussed this issue extensively. Energy companies face substantial financial risks since both prices and quantities may be highly volatile. To mitigate these risks, market participants may use an array of financial products. In mature energy markets, the products are fairly standardized. However, more complex and tailor-made financial products are required to face the ongoing changes in the sector. For example, the increased share of renewable energy combined with more interconnected markets create specific market risks. To hedge against risks associated with weather changes, future fuel costs, interest rates and so on, more and more energy providers trade customized derivatives “over-the-counter” (OTC) rather than through a centrally-cleared exchange. Another example is the development of decentralized power production and the rise of the “Prosumer” who simultaneously produces and consumes power. So far, the relevant regulation is underdeveloped and there is an additional demand for innovative financial solutions. Large energy companies such as Vattenfall are for instance offering a range of financial hedging solutions combined with actual physical handling and delivery of energy products.
Green transition should in the long run lead to a domination of environment friendly energy. However it is important that only economically viable technologies subsist. It is therefore necessary to assess the cost of producing green energy. Lars Andersson, Head of Wind Power Unit at the Swedish Energy Agency, reported on an extensive study done by the Agency on this issue. Over the last five years, the production cost of wind power has fallen consistently and capacity usage has increased. This dramatic change in the wind power industry likely implies that the existing subsidies for building wind power plants gradually will be phased out. It is unclear how the industry will react to these cuts in subsidies. Furthermore, according to Andersson, wind production faces at least two challenges. Without developing the capabilities for energy storage, electricity markets will face more energy imbalances as the share of wind power increases. Additionally, the support from the local communities is needed to ensure an expansion of wind power. Addressing these issues requires the development of new regulation and defining a common goal which may promote cooperation between stakeholders.
Ultimately the green transition will end when and if the green energies are largely adopted around the globe. One way to accelerate this green transition may be to coordinate action and development of governmental policies. Martin Ådahl, Chefsekonom at Centerpartiet, and Daniel Engström, Programchef Miljö och Klimat at Fores, presented the current state of the international climate policy and discussed the benefits of linking carbon emission rights markets. Because of conflicting interests, the likelihood of reaching an agreement within the current United Nations climate negotiations is rather small.
However, Ådahl and Engström suggested that the focus should instead be on reaching agreements between big polluter countries that contribute the lion’s share of global emissions. Indeed, regional emission trading schemes already exist in the EU, the US and China, the three regions which together account for over 50 percent of global emissions. One potential shortcoming of this suggestion is that it may not be enough to stabilize greenhouse gas concentrations in the atmosphere. Thereby, Ådahl and Engström discussed the possibility to link current cap-and-trade markets, as a first step toward an international system with a more formal global agreement. Linking cap-and-trade markets has many benefits, especially in the form of efficiency gains. However, emission caps vary across countries and regions because of different political goals or priorities. When markets are linked, difference in abatement costs (or allowance prices) would lead to a flow of allowances and emissions from countries/regions with low abatement cost to countries with higher ones. Thereby prices would be equalized, benefiting entities with cheaper allowances. To avoid opportunistic behavior, countries would first have to agree ex ante on an exchange rate between different countries’ emission rights. Second, a clear regulatory framework is required. Both Ådahl and Engström emphasized the need of an international organization devoted to climate economics. Such an institutional body could not only regulate the links between cap-and-trade markets, but also provide concrete solutions and technical models to improve on the market design.
Environmental Policies: International Experience
The second panel focused on how governments may promote green transition. Anna Pegels, Senior Researcher at the German Development Institute (DIE), reviewed green policy initiatives in developing countries. Pegels argued based on evidence from e.g. India and South Africa that it is possible to combine substantial growth with green energy. This is good news since emerging countries are among the highest polluters. However, to change a country’s energy profile, governments need to intervene and develop new industrial policies.
Governments can set long-term goals, which are supported by short- and mid-term targets. However, given the large profits that are at stake, officials may likely be subject to the risk of capture and corruption. To limit such risks, Pegel emphasized the need to introduce competition in the energy sector as a whole. Subsidized feed-in tariffs for renewable energy for example should be only a first step, to reach a certain scale of production. But the technology is mature enough that producers should be able to bear some additional risk in their current activity. This should increase the scope for competition. Finally, it is essential that governments continuously engage in policy revision cycles and learn from other countries’ experiences.
Benjamin Sovacool, Professor of Business and Social Sciences at Aarhus University and Director of the Danish Centre for Energy Technologies, talked about the process of low carbon transition in the Nordic region. In spite of large investments into renewable energy, fossil fuels still dominate the consumption in the Nordic countries and considerable measures need to be taken in the decades ahead to make the transition to a greener energy mix. Sovacool highlighted four areas which could help reduce the carbon footprint of the Nordic countries: renewable energy, increased energy efficiency of buildings, transportation, and carbon capture and storage (CCS). In order to be successful, the green transition has to bring about a systemic change engaging actors across the economy, particularly including end-users. There should also be a focus on additional technological progress. Finally, Sovacool noted that a rapid emission reduction such as the one planned in the Nordic countries is unlikely to be followed on a global scale in the near future due to a lack of political feasibility.
The green transition is expected to have a profound impact on the functioning and structure of energy markets as well as the policies that facilitates this transition.
There is an ongoing process of decentralization in the energy sector, with the rise of “prosumer” market places that alter market dynamics. Moreover, market uncertainty is increasing due to more intermittent production (due to renewables) and a stronger interconnectedness between energy markets. It is likely that energy imbalances will be a major concern and that more and more energy trade will take place on real time markets (as opposed to e.g. on the day-ahead market). As markets’ linking becomes stronger, the interdependence between markets in terms of energy type and geographical location will be intensified. The need for coordination and international cooperation will be even more pressing. The uncertainty regarding the development of international cooperation, but also regarding national policy changes, may however disrupt energy markets. Measures such as withdrawing existing subsidies must be handled in a gradual and strategic manner so as not to discourage investment. A key issue for governments is to have a credible green policy in the long-term. Such credibility will also depend on the level of involvement of different actors in the green transition, including the necessity to have a multilevel engagement of the end-users.
- Energimyndigheten, (2014), Produktionskostnads-bedömning för Vindkraft i Sverige, ER 2014:16
- Pegels, A. (Ed.). (2014), Green industrial policy in emerging countries, Vol. 34, Routledge
- Rutqvist, J., Engström, A.and Ådahl, M., A Bretton Woods for the Climate. Fores, 2010
- SITE 8th Energy Day, http://www.hhs.se/en/about-us/calendar/site-external-events/2014/site-energy-day/
- UNFCCC, (n.d). First steps to a safer future: Introducing The United Nations Framework Convention on Climate Change, http://unfccc.int/essential_background/convention/items/6036.php [8 December 2014]
This brief addresses the economic costs of a potential Russian gas sanction considered by the EU. We discuss different replacement alternatives for Russian gas, and argue that complete banning is currently unrealistic. In turn, a partial reduction of Russian gas imports may lead to a loss of the EU bargaining power vis-à-vis Russia. We conclude that instead of cutting Russian gas imports, the EU should put an increasing effort towards building a unified EU-wide energy policy.
Soon after Russia stepped in Crimea, the question of whether and how the European Union could react to this event has been in the focus of political discussions. So far, the EU has mostly implemented sanctions on selected Russian and Ukrainian politicians, freezing their European assets and prohibiting their entry into the EU, but broader economic sanctions are intensively debated.
One such sanction high on the political agenda is an EU-wide ban on imports of Russian gas. Such a ban is often seen as one of the potentially most effective economic sanctions. Indeed the EU buys more than half of total Russian gas exports (BP 2013), and gas export revenues constitute around one fifth of the Russian federal budget (RossBusinessConsulting,2012 and our calculations). Thus, by banning Russian gas the EU may indeed be able to exert strong economics pressure on Russia.
However, the feasibility of such sanction is questionable. Indeed, in 2012 Russia supplied around 110 bcm of natural gas to EU-28 (Eurostat), which constitutes 22.5% of total EU gas consumption. There are a number of alternatives to replace Russian gas, such as an increase in domestic production by investing in shale gas, or switching to other energy sources, such as nuclear, coal or renewables. However, many of the above alternatives, e.g. shale gas or nuclear power, involve large and time-consuming investments, and thus cannot be used in the short run (say, within a year). Others, such as wind energy, are subject to intermittency problem, which again requires investments into a backup technology. The list of alternatives implementable within a short horizon is effectively down to replacing Russian gas by gas from other sources and/or switching to coal for electricity generation. Below, we argue that even if such a replacement is feasible, it is likely to be very costly for the EU, both economically and environmentally.
Notice that any replacement option will be automatically associated with a significant increase in economic costs. This is due to the fact that a substantial part of Russian gas exports to Europe (e.g., according to Financial Times, 2014 – up to 75%) are done under long-term “take-or-pay” contracts. These contracts assume that the customer shall pay for the gas even if it does not consume it. In other words, by switching away from Russian gas, the EU would not only incur the costs of replacing it, but also incur high financial or legal (or both) costs of terminating the existing contracts with Russia, with the latter estimated to be around USD 50 billion (Chazan and Crooks, Financial Times, 2014).
Due to this contract clause, own costs of replacement alternatives become of crucial importance. The coal alternative is currently relatively cheap. However, a massive use of coal for power generation is associated with a strong environmental damage and is definitely not in line with the EU green policy.
What about the cost of reverting to alternative sources of gas? First, in utilizing this option, the EU is bound to rely on external and potentially new gas suppliers. Indeed, the estimates of potential contribution within the EU – by its largest gas producer, the Netherlands – are in the range of additional 20 bcm (here and below see Zachmann 2014 and Economist 2014). Another 15-25 bcm can be supplied by current external gas suppliers: some 10-20 bcm from Norway, and 5 bcm from Algeria and Libya. This volume is not sufficient for replacement, and is not likely to be cheaper than Russian gas.
This implies that the majority of the missing gas would need to be replaced through purchases of Liquefied Natural Gas (LNG) on the world market, in particular, from the US. This option may first look very appealing. Indeed, the current gas price at Henry Hub, the main US natural gas distribution hub, is 4.68 USD/mmBTU (IMF Commodity Statistics, 2014). Even with the costs of liquefaction, transport and gasification – which are estimated to be around 4.7 USD/mmBTU (Henderson 2012) – this is way lower than the current price of Russian gas at the German border (10.79 USD/mmBTU, IMF).
However, this option is not going to be cheap. A substantial increase in the demand for LNG is likely to lead to an LNG price hike. Notice that, at the abovementioned prices, US LNG starts losing its competitive edge in Europe already at a 15% price increase. Just for a very rough comparison, the 2011 Fukushima disaster lead to 18% LNG price increase in Japan in one month after disaster. Some experts are expecting the price of LNG in Europe to rise as much as two times in these circumstances (Shiryaevskaya and Strzelecki, Bloomberg, 2014).
Moreover, it is not very likely that there will be sufficient supply of LNG, even at increased prices. For example, in the US, which is the main ”hope” provider of LNG replacement for Russian gas, only one out of more than 20 liquefaction projects currently has full regulatory approval for imports to the EU. This project, Cheniere Energy’s Sabine Pass LNG terminal, is planned to start export operations no earlier than in the 4th quarter of 2015 with a capacity of just above 12bcma (World LNG Report, 2013). Of course, there are other US and Canada gas liquefaction projects currently undergoing regulatory approval process, but none of them is going to be exporting in the next year or two. Another potential complication is that two thirds of the world LNG trade is covered by long-term oil-linked contracts (World LNG Report, 2014), which significantly restricts the flexibility of short-term supply reaction, contributing to a price increase. All in all, LNG is unlikely to be a magical solution for Russian gas replacement.
All of the above discussion suggests that it may be prohibitively expensive for the EU to do completely without Russian gas. Maybe the adequate solution is partial? That is, shall the EU cut down on its imports of natural gas from Russia, by, say, a half, instead of completely eliminating it?
On one hand, this may indeed lower the costs outlined above, such as part of take-or-pay contract fines, or costs associated with an LNG price increase. On the other hand, cutting down on Russian gas imports may lead to an important additional problem, loss of buyer power by the EU.
Indeed, the dependence on the gas deal is currently mutual – as outlined above, not only Russian gas is important for the EU energy portfolio; the EU also represents the largest (external) consumer of Russian gas, with its 55% share of the total Russian gas exports. In other words, the EU as a whole possesses a substantial market power in gas trade between Russia and the EU, and this buyer power could be and should be exercised to achieve certain concessions, such as advantageous terms of trade from the seller etc.
However, the ability to have buyer power and to exercise it depends crucially on whether the EU acts as a whole to exercise a credible pressure on Russia. That is, the EU Member States may be much better off by coordinating their energy policies rather than diluting the EU buyer power by diversifying gas supply away from Russia. This coordination may be a challenge given the Member States’ different energy profiles and environmental concerns. Also, such coordination requires a stronger internal energy market that will allow for better flow of the gas between the Member States. While demanding any of these measures would be double beneficial: they will improve the internal gas market’s efficiency, and at the same time reinforce the EU’s buyer power vis-à-vis Russia.
To sum up, the EU completely banning Russian gas imports does not seem a feasible option in the short run. In turn, half-measures are not necessarily better due to the loss of the EU’s buyer power. Thereby, the best short-term reaction by the EU may be to put the effort into working up a strong unified energy policy, and to place “gas at the very back end of the sanctions list” for Russia as suggested by the EU energy chief Gunther Oettinger (quoted by Shiryaevskaya and Almeida, Bloomberg, 2014).
- BP, 2013, Statistical review of the world energy
- Chazan, Guy and Ed Crooks, Financial Times, April 3, 2014, Europe’s dangerous addiction to Russian gas needs radical cure
- Economist, April 6, 2014, Conscious uncoupling
- Eurostat energy statistics
- Henderson, James, 2012, “The potential impact of North American LNG exports”, Oxford Institute for Energy Studies, Working Paper NG 68, Oxford,
- IMF commodity statistics, April 2014
- Le Coq, Chloé and Elena Paltseva, 2013, “EU-Russia Gas Relationship at a Crossroads”, in “Russian Energy and Security up to 2030”, edited by Susanne Oxenstierna and Veli-Pekka Tynkkynen, Roothledge
- RossBusinessConsulting,Feb 6, 2012, “Доходы РФ от экспорта нефти и газа выросли в 2011 г. на треть» (The revenues of Russia from oil and gas export have growth by a third in 2011)
- Shiryaevskaya and Strzelecki, Bloomberg, Mar 28, 2014, Europe Seen Paying Twice as Much to Replace Russian Gas
- Shiryaevskaya and Almeida, Bloomberg, May 7, 2014, Europe Gas Options Seen Limited by Costs at $200 Billion
- World LNG Report, 2013, International Gas Union (IGU)
- World LNG Report, 2014, International Gas Union (IGU)
- Zachmann, Georg, Bruegel, March 21, 2014, Can Europe survive without Russian gas?
Author: Mykhaylo Salnykov, BEROC
Energy security is a complex phenomenon incorporating a variety of economic, social and environmental aspects of a country’s life. Building on a previous FREE policy brief, published on September 5, which dealt mainly with the situation up until today, this text deals more with the future. It takes a detailed look at existing trends and discusses potential positive effects and challenges to energy security in Belarus. It also provides potential measures for addressing adverse effects of these trends on the country’s energy security.
When evaluating energy security consequences of external and internal factors, a decision maker is advised to view energy security as a complex phenomenon. The main components of Belarusian energy security identified in the first part of this paper published in the FREE Policy Brief Series September 5, 2011, include (i) primary energy source distribution (diversification of energy sources, especially away from natural gas as well as reducing the economy’s energy intensity), (ii) international trade considerations, (iii) the geopolitical context (with a special focus on diversification of energy suppliers and an optimal use of the country’s gas- and oil- transporting systems), and (iv) environmental considerations of the energy use (related to both actual and the perceived impact of the energy production and consumption on the environment).
Other dimensions of energy security also include the social impact of energy production and consumption, as well as the sustainability of energy use.
Below, I provide a detailed look at these and other existing trends. Potential positive effects and challenges in the context of energy security of Belarus will also be discussed. Finally, potential measures of addressing adverse effects of these trends on the country’s energy security will be suggested.
Main Energy Security Challenges for Belarus in 2011-2020
The following components of the energy security of Belarus are considered to be of primary importance:
- Reducing energy intensity of the economy;
- Diversification of energy sources used in heat and power generation, especially diversification away from natural gas consumption;
- Diversification away from Russian fuel imports;
- Securing stable operation of gas and oil pipeline systems close to full capacity;
- Reducing impact of energy production and consumption on the environment.
The main trends in Belarusian and regional policy and economy, as well as their impacts on the aforementioned components of energy security are the following:
- Natural shale gas and liquefied natural gas revolution in Europe;
- Launch of the Nord Stream gas pipeline system in 2011-2012;
- Construction of nuclear power plant station in Astravets;
- New suppliers of hydrocarbons to Belarus.
I will purposefully not discuss important topics as carbon-free technologies development in Belarus, participation in the international carbon-reduction dialog, etc., since these trends are unlikely to become anything close to significant determinants of the Belarusian energy security puzzle within the next decade.
Natural Shale Gas and LNG Revolution in Europe
Recent developments in the technology of natural shale gas extraction in Europe and elsewhere, bring a lucrative prospect of boosting the world’s natural gas supply. Several of the European countries, including Austria, Germany, Hungary, Poland, Sweden, Ukraine and United Kingdom have announced plans to study fields with shale gas extraction potential. This could secure European gas supplies, drive gas prices in Europe down, and diversify European imports away from Russian natural gas. The natural shale gas extraction development factor will be further reinforced by the increased volumes of the LNG imports to Europe from the Americas and Northern Africa.
Contraction of gas prices in the European market will positively affect Belarusian economy as natural gas imports from Russia will become less expensive even if no active steps by the Belarusian government are undertaken. Nevertheless, the natural shale gas and LNG revolution will also widen the body of potential importers of natural gas via pipelines from Poland and Ukraine and by sea freight from seaports in the Baltic States. Specifically, in the summer of 2010, the Belarusian government announced having plans of negotiating a possible construction of a Belarusian LNG terminal in Lithuanian Klaipeda. This terminal is projected to have an annual capacity of five to eight billion cubic meters of natural gas which would be transported to Belarus via the pipeline system.
The shortcoming of the lower prices for natural gas and diversified body of importers in Europe is a reduced demand for Belarusian natural gas transit capacity as Russian exports to Europe contract. Moreover, potential transportation of shale gas from Poland via the pipeline system (see Figure 1) is likely to conflict with the Russian gas transit going into the opposite direction. From an economic perspective, it is very likely that benefits for Belarus obtained from lower gas prices will overweight potential losses from the reduced transit of Russian natural gas to Europe.
Figure 1. Natural gas and oil pipeline systems in Eastern Europe.
From a political perspective, Belarus losing its role as a transit country would substantially weaken its position in foreign relations with both Russia and Europe.
A possible side effect of the lower prices for natural gas is reduced incentives for the Belarusian government to reform power and heat generating sector and contract the energy intensity of the economy. While the former outcome may be economically justified by lower gas prices and diversified sources of natural gas in the new economic environment, the latter raises serious concerns over the pace of economic modernization in the country.
On the other hand, the environmental impact is mixed. While lower incentive to modernize the economy could result in a slower progress of lowering the pollution intensity in energy use, increased incentives to use natural gas, one of the environmentally friendliest hydrocarbons, would play a positive role in ensuring that the intensity of pollution reduces.
Launch of the Nord Stream Pipeline System
Dubbed by the Belarusian President, Aliaksandr Lukashenka “the silliest Russian project ever”, the Nord Stream pipeline system will allow Russia to redirect 55 billion cubic meters of natural gas (nearly 33% of the current Russian gas exports) via this more direct route to the final consumers. Thus, if European demand for Russian gas stays unchanged, the gas transit through Belarus and Ukraine will drop to nearly 100 billion cubic meters from the current 158 billion cubic meters. The 100 billion cubic meters figure is close to the capacity of the Ukrainian gas pipeline system alone. Therefore, one may hypothesize that in the worst case scenario Belarus may suffer a complete loss of its gas transit revenues.
In fact, even optimistic scenarios of the distribution of the residual transit demand between Ukrainian and Belarusian pipeline systems, imply both a substantial reduction of volumes transferred via Belarusian pipeline system, and a decline in transit tariffs triggered by strong price competition between Belarus and Ukraine. As a result, profits from the gas pipeline system in Belarus are likely to diminish.
This negative outcome is reinforced by the above mentioned trends of increased extraction of natural shale gas in Europe as well as prospective development of the LNG trading routes with Northern Africa and Americas. A conservative estimation of the reduction of European demand for Russian natural gas indicates that it can be reduced by 28 billion cubic meters (17% of the current Russian imports). Coupled with the launch of the Nord Stream, the decline of transit volumes through Belarus and Ukraine can be nearly 75 billion cubic meters annually, which is more than a 50% reduction from current levels.
Notably, these 28 billion cubic meters is an equivalent of the natural gas consumption by Poland and Hungary alone, the European countries currently most dependent on Russian gas imports.
Thus, the launch of the Nord Stream presents a substantial threat to the stable operation of the Belarusian gas pipeline system and requires careful policy steps (which will be discussed further ahead).
The fact that Belarus loses an important lever of its transit capacity may lead to lower negotiation power in fuel prices dialog with Russia, thus, leading to the smaller subsidies for the Russian oil and gas imports. However, a reduction of the world gas prices due to the growing European production of natural gas and LNG trade is likely to at least partly offset this effect.
Reduced profits received from the natural gas transit is likely to lead to a decrease of budget funds available for technological modernization of the Belarusian economy, which, in turn, may lead to an inadequate pace of changes in energy efficiency and pollution intensity of energy use as well as slower modernization of the power and heat generating sector and diversification away from the natural gas use.
On the other hand, the launch of the Nord Stream and reduced negotiation power towards Russia could increase incentives for Belarus to diversify away from Russian fuel imports as subsidies for the Russian oil and gas imports will contract.
Construction of Astravets Nuclear Power Plant
Although the launch of the Astravets nuclear power plant is unlikely to happen before 2017-2018, debates around this controversial project and its rationale requires a discussion of its energy security implications long before the plant is constructed.
The projected two-reactor nuclear power plant has an operating capacity of 2.4 GW. Unadjusted for load fluctuations in demand, this figure is an equivalent of 63.5% of the electricity consumption in Belarus. A rough seasonally unadjusted estimate of the Astravets nuclear power plant electricity production is a 35-40% of the daily peak load electricity consumption in the country – a usual figure for the baseload demand figure. Therefore, it is expected that once in full operation, Astravets plant could provide for the entire baseload demand on electricity in Belarus.
Some opponents of the Astravets plant construction note that the plant’s capacity may be excessive as several other nuclear power plants are being constructed in the region, including a plant in Lithuania and Russia’s Kaliningrad oblast. It is suggested that it may be optimal for Belarus to purchase electricity from these plants rather than constructing its own. This view, however, does not take into consideration two important issues. Firstly, it is highly unlikely that anything but the excess baseload electricity production will be traded (i.e. limited volumes of energy at night for approximately 5 to 6 hours per day); at all other time Belarus would need to rely entirely on its thermal power plants to generate electricity. Secondly, shifting from the dependence on hydrocarbon imports to the dependence on electricity imports will not cause a substantial improvement of the country’s energy security.
Current production of electricity by fossil fuel operated power plants in Belarus is an equivalent of 18 TWh, 55% of the total electricity consumption in the country. A launch of the Astravets nuclear power plant would allow reducing fossil fuel operated power plants’ utilization to virtually zero level. In addition, nearly 15% of the combined heat and power plants may operate as heat plants only.
Yet, it is unlikely to lead to the substantial changes in the usage of the existing heat plants: while nuclear power plants can provide heat, Astravets is located far from densely populated regions of Belarus, which makes heat delivery to the final consumer close to impossible because of the high losses in transfer.
As a result of decreased utilization of power plants and CHP plants, demand for natural gas from the heat and power generating sector will be reduced by 38%. Thus, the share of natural gas in the sector’s consumption balance will shrink to nearly 50% from the current 91% figure. The Astravets plant launch will also lead to nearly 25% reduction of the sector’s demand for petroleum products.
Therefore, the economy-wide TPES of natural gas is likely to contract by 28.5% and TPES of crude oil and petroleum products by nearly 2% once the Astravets plant is in full operation. The estimated annual benefit from the reduced imports of hydrocarbons is likely to reach USD 1 billion at current fuel prices.
Overall, Astravets power plant launch is expected to have strongly positive effect on diversification of energy sources in heat and power generating sector as nuclear power will gain the second largest share among the energy sources used in the sector and the natural share will reduce to nearly 50% of the total consumption by the sector. The plant construction is also likely to have a positive effect on the energy intensity by reducing losses from the power generating sectors and by closure of obsolete plants.
Moreover, the effect on diversifying fuel imports away from Russia is two-fold. Although Belarus will be able to reduce its Russian gas imports by almost a third of its current level, nuclear fuel for the Astravets station is likely to be imported from Russia. Nevertheless, given positive shifts in Belarusian regime’s relations with the West, it is highly likely that by the time of the power plant launch, the current suspicion of the Belarusian government by the international community will have vanished and alternative importers of uranium would then become an option.
Overall, the Astravets plant will have very limited impact on Belarus’ role as a transit corridor for Russian hydrocarbons.
Environmental consideration is probably the most controversial issue with respect to the projected plant. The issue becomes even more uncertain when one takes into account not only objective environmental costs and benefits, but also subjective factors, such as suspicion of Belarusians to nuclear power – a legacy of the Chernobyl accident.
A nuclear power plant will undoubtedly lead to a reduction of pollution intensity in the Belarusian economy. Yet, there are a number of factors that may offset the seeming gains. Firstly, a low probability of technological disaster at the power plant, mean that most Belarusians consider the plant as an environmentally but dangerous project for the country. Secondly, Lithuanian environmentalists have expressed their concerns over the proximity of the projected plant to the Lithuanian capital, Vilnius (only 40 km), especially as the Neris (Viliya) river that flows through Vilnius will be the main water source for the Astravets plant. Thirdly, international environmental experts rarely consider nuclear power plants considerably greener than their fossil fuel operated counterparts as uranium extraction and enriching produces substantial amounts of polluting substances at their fuel producing facilities. Finally, spent nuclear fuel treatment still remains one of the issues without a sustainable technological solution. Belarus is likely to export its nuclear waste to either Russia or Ukraine that have spent nuclear fuel storage facilities.
Therefore, from an environmental perspective, while Belarus will enjoy most of the benefits of the cleaner power generation, it is likely to create substantial trans-boundary environmental risks mostly for Lithuania, Russia and Ukraine.
New suppliers of hydrocarbons
Belarus currently attempts to diversify its oil supply by shipping Venezuelan crude to Black Sea and Baltic Sea ports. In addition, there exists a sound potential of diversifying Belarusian natural gas imports by gaining access to Ukrainian and Polish natural shale gas deposits as well as through constructing an LNG terminal at the Baltic Sea.
While the perspectives of these recent international advancements are not certain, in the case of sustainable progress they are likely to have important implications for the energy security of Belarus, which are closely interrelated to the implications of the shale gas and LNG revolution.
Emergence of new suppliers of hydrocarbons will have a positive impact on diversifying away from Russian fuel imports, but will also reduce incentives for the energy intensity and pollution intensity reduction as well as the modernization of the heat and power generating sector as economic stimuli for technological modernization fade away.
Diversification of hydrocarbon suppliers presents risks for the usage of Belarusian gas and oil pipeline systems. If oil would be transported from either Black Sea or Baltic Sea ports, this oil would compete with the Russian oil transport routes headed into the opposite direction to either Ukrainian Odesa seaport or Baltic refineries (see Figure 1). Pipeline transportation of shale gas from Poland would compete with Russian natural gas going in the opposite direction. At the same time, reduced revenues from transit of Russian hydrocarbons may be overweighed by benefits incurred from lower prices for hydrocarbons from the alternative sources.
Table 1 provides a summary of the reviewed trends and their impact on the energy security challenges faced by Belarus.
Table 1. Summary of the existing trends and their impact on energy security of Belarus
Table 1 suggests that the most of the vital energy security components will experience both positive and negative shocks in the nearest future. Nevertheless, it is possible to undertake a number of policy measures to enhance positive effects and secure against risks.
Reducing energy intensity of economy
All possible negative effects on the energy intensity reduction will be a result of either lowering incentives to modernize the existing technologies due to lower hydrocarbons prices or a reduced capacity to modernize due to drop in budget revenues. Yet, as discussed above, improving energy efficiency may become an important driver of economic growth in the foreseeable future.
Besides already existing Energy Efficiency Department of the Committee for Standardization and construction of the Astravets power plant having a positive impact on the energy intensity of the economy, the Belarusian government may also consider the following options:
- Establishing a Research and Development (R&D) program on energy efficiency;
- Creating a special energy efficiency fund to be used for the modernization and energy intensity reduction measures;
- Imposing standards of energy use, especially in energy intensive sectors;
- Introducing taxation schemes on energy use with industry-specific energy intensity reference values in order to provide additional incentives for businesses to undertake modernization and reduce energy intensity;
- Issuing a mandate requiring gradual replacement and rehabilitation of obsolete equipment, especially in heat and power generating and energy intensive industrial sectors.
Heat and power generating sector diversification away from gas
Similarly, to the energy intensity challenge, the HPG sector diversification away from gas will be negatively affected by the reduced incentives to modernize and the lack of budget funds to impose these modernizations. Hence, the following measures may be considered:
- Ensuring adequate progress of the Astravets power plant construction;
- Imposing standards and taxation schemes of energy use by the sector;
- Study options for electricity imports, especially in off-peak hours;
- Gradually replace and rehabilitate obsolete equipment.
A number of steps to encourage use of specific fuel sources can be undertaken:
- Study possibilities of expanding production and/or imports of coal;
- Transfer some smaller-scale heat plants to coal and/or wood as environmental conditions permit;
- Integrate production of fuel wood into conventional forestry and industrial timber procurement;
- Assure quality standards and efficient use for forest chips.
While not being directly related to the sector’s diversification away from natural gas, the following measures will allow improving financial performance of the sector and, thus, providing additional resources to undertake modernizations in the sector:
- Separate commercial operation of the sector’s state-owned companies from the government’s conflicting position as an owner, policy setter and regulator;
- Imposing reporting standards, such as IFRS standards, in the sector in order to improve financial management of the companies and attract possible financiers;
- Adopt and implement OECD 2005 Guidelines on corporate governance of state-owned enterprises. While a number of the guidelines are not applicable to the Belarusian noncorporatized companies such as Belenergo and Beltopgas, general principle allow for more effective management of the companies.
I purposefully omit an option of the ownership change of the heat and power generating sector’s companies in our policy recommendations, since this option is not consistent with the existing economic and political environment in Belarus.
Diversification away from Russian fuel imports
While all of the trends analyzed will have positive effect on diversification away from Russian fuel imports, this seeming progress is largely due to the fact that up until recently Belarus has been totally dependent on Russia’s fuel imports. Yet, a number of steps can be undertaken to further augment the diversification progress:
- Ensuring adequate progress of the projects enhancing the diversification away from Russian fuel supply, namely LNG terminal in Kaunas, Astravets power plant and search of alternative suppliers of hydrocarbons;
- Exploring possibility to access and explore Polish and Ukrainian shale gas fields with a possibility to operate some of the extraction facilities;
- Studying an option to create a coal-bed methane extracting consortium with Ukraine to develop technology and extract coal-bed methane in coal-rich Eastern Donbas region;
- Researching and developing biomass as a source of energy to replace a share of oil and gas usage.
Usage of pipeline system up to full capacity
It is next to certain that the configuration of the hydrocarbon routes in Eastern Europe is about to go through fundamental changes in the nearest future due to both reduced demand for Russian hydrocarbons from Europe and the launch of the Nord Stream pipeline system. Still, there exist a number of steps to ensure that Belarusian pipeline system is in operation and is enhancing the country’s energy security:
- Creating a gas-transporting consortium with Ukraine to gain an additional market power to ensure adequate transit tariffs and share of volumes of the residual Russian gas exports to Europe after Nord Stream is launched;
- If Russian hydrocarbons transit volumes fall below critical level, transfer to the reverse direction to make the best use of the Polish shale gas and Baltic seaports’ ability to receive oil for Belarus. By doing so, Belarus will ensure both hydrocarbons imports diversification and adequate operation of its pipeline systems;
- Continuing search for alternative suppliers of oil and natural gas (including LNG) in order to assure adequate usage of the pipeline systems in the reverse direction.
Similarly to energy intensity considerations, most of the negative effects of the current trends on the environment are related to either reduced incentives to modernize or reduced funds available for modernization projects. The following measures are intended to reduce pollution intensity of energy use:
- Establishing a Research and Development (R&D) program on environmental effects of energy use;
- Imposing environmental standards and taxes on energy use, especially in energy intensive sectors and bringing these policies closer to international standards;
- Issuing a mandate requiring gradual replacement and rehabilitation of obsolete equipment, especially in heat and power generating and pollution intensive industrial sectors;
- Establishing emission trade relations with the Kyoto Protocol Annex B countries to collect funds for the environmental modernization of equipment.
The following steps should be undertaken to minimize both actual and perceived environmental risks of the Astravets nuclear power station:
- Working with the general public to educate them about modern technologies that guarantee nuclear power safety as well as inform them of virtually accident-free record of civil nuclear power besides Chernobyl disaster;
- Establishing relations with the stakeholders that might be affected by the environmental impact of the projected power station, especially, local communities along Neris river;
- On early stages, study the possibilities for the spent nuclear fuel treatment and reach the preliminary international agreements over the potential nuclear waste storage if needed;
- Ensure compliance with the international standards of the power plant construction and operation and advertise this compliance strategy to the stakeholders.
Currently Belarus enters a completely new stage of its development as the old economic growth factors vanish, the political situation both within and outside the country transforms, and the geopolitical context changes. This new stage of the country’s development presents new challenges and new opportunities for Belarusian energy security, the key for any country’s independence. Careful consideration of the most critical energy security challenges coupled with professional and effective policy measures to tackle them is a vital task for securing Belarus’ economic growth, political sovereignty and quality of life improvement.