Over the last two years, the world has experienced a global energy crisis, with surging oil, coal, and natural gas prices. For European households, this translates into higher gasoline and diesel prices at the pump as well as increased electricity and heating costs. The increase in energy related costs began in 2021, as the world economy struggled with supply chain disruptions caused by the Covid-19 pandemic, and intensified as Russia launched a full-scale invasion of Ukraine in late February 2022. In response, European governments have implemented a variety of energy tax cuts (Sgaravatti et al., 2023), with a particular focus on reducing the consumer cost of transport fuel. This policy paper aims to contextualize current transport fuel prices in Europe by addressing two related questions: Are households today paying more for gasoline and diesel than in the past? And should policymakers respond by changing transport fuel tax rates? The analysis will focus on case studies from Sweden, Georgia, and Latvia, countries that vary in economic development, energy independence, reliance on Russian oil, transport infrastructure, and transport fuel tax rates. Through this study, we aim to paint a nuanced picture of the implications of rising fuel prices on household budgets and provide policy guidance.
Record High Gasoline Prices, Historically Cheap to Drive
Sweden has a long history of using excise taxes on transport fuel as a means to raise revenue for the government and to correct for environmental externalities. As early as in 1924, Sweden introduced an energy tax on gasoline. Later, in 1991, this tax was complemented by a carbon tax levied on the carbon content of transport fuels. On top of this, Sweden extended the coverage of its value-added tax (VAT) to include transport fuels in 1990. The VAT rate of 25 percent is applied to all components of the consumer price of gasoline: the production cost, producer margin, and excise taxes (energy and carbon taxes).
In May 2022, the Swedish government reduced the tax rate on transport fuels by 1.80 SEK per liter (0.16 EUR). This reduction was unprecedented. Since 1960, there have only been three instances of nominal tax rate reductions on gasoline in Sweden, each by marginal amounts in the range of 0.04 to 0.22 SEK per liter. Prior to the tax cut, the combined rate of the energy and carbon tax was 6.82 SEK per liter of gasoline. Adding the VAT that is applied on these taxes, amounting to 1.71 SEK, yields a total excise tax component of 8.53 SEK. This amount is fixed in the short run and does not vary with oil price changes.
Figure 1. Gasoline Pump Price, 2000-2023.
Source: Drivkraft Sverige (2023).
Figure 1 shows the monthly average real price of gasoline in Sweden from January 2000 to October 2023. The price has slowly increased over the last 20 years and has been historically high in the last year and a half. Going back even further, the price is higher today than at any point since 1960. Swedish households have thus lately been paying more for one liter of gasoline than ever before.
However, a narrow focus on the price at the pump does not take into consideration other factors that affect the cost of personal transportation for households.
First, the average fuel efficiency of the vehicle fleet has improved over time. New vehicles sold in Sweden today can drive 50 percent further on one liter of gasoline compared to new vehicles sold in 2000. Arguably, what consumers care about the most is not the cost of gasoline per se but the cost of driving a certain distance, as the utility one derives from a car is the distance one can travel. Accounting for vehicles’ fuel efficiency improvement over time, we find that even though it is still comparatively expensive to drive today, the current price level no longer constitutes a historical peak. In fact, the cost of driving 100 km was as high, or higher, in the 2000-2008 period (see Figure 2).
Figure 2. Gasoline Expenditure per 100 km.
Source: Trafikverket (2023) and Drivkraft Sverige (2023).
Second, any discussion of the cost of personal transportation for households should also factor in changes in household income over time. The Swedish average real hourly wage has increased by more than thirty percent between 2000-2023. As such, the cost of driving 100 km, measured as a share of household income, has steadily declined over time. Further, this pattern is consistent across the income distribution; for instance, the cost trajectory for the bottom decile is similar to that of all wage earners (as illustrated in Figure 3). In 1991, when the carbon tax was implemented, the average household had to spend around two thirds of an hour’s wage to drive 100 km. By 2020, that same household only had to spend one third of an hour’s wage to drive the same distance. There has been an increase in the cost of driving over the last two years, but in relation to income, it is still cheaper today to drive a certain distance compared to any year before 2013.
Figure 3. Cost of Driving as a Share of Income, 1991-2023.
Source: Statistics Sweden (2023).
Taken all together, we see that on the expenditure side, vehicles use fuel more efficiently over time and on the income side, households earn higher wages. Based on this, we can conclude that the cost of travelling a certain distance by car is not historically high today.
Response From Policymakers
It is, however, of little comfort for households to know that it was more expensive to drive their car – as a share of income – 10 or 20 years ago. We argue that what ultimately matters for households is the short run change in cost, and the speed of this change. If the cost rises too fast, households cannot adjust their expenditure pattern quickly enough and thus feel that the price increase is unaffordable. In fact, the change in the gasoline price at the pump has been unusually rapid over the last two years. Since the beginning of 2021, until the peak in June 2022, the (nominal) pump price rose by around 60 percent.
So, should policymakers respond to the rapid price increase by lowering gasoline taxes? The perhaps surprising answer is that lowering existing gasoline tax rates would be counter-productive in the medium and long run. Since excise taxes are fixed and do not vary with the oil price, they reduce the volatility of the pump price by cushioning fluctuations in the market price of crude oil. The total excise tax component including VAT constitutes more than half of the pump price in Sweden, a level that is similar across most European countries. This stands in stark contrast with the US, where excise taxes make up around 15 percent of the consumer price of gasoline. As a consequence, a doubling of the price of crude oil only increases the consumer price of gasoline in Sweden by around 35 percent, while it increases by about 80 percent in the US. Households across Sweden, Europe, and the US have adapted to the different levels of gasoline tax rates by purchasing vehicles with different levels of fuel efficiency. New light-duty vehicles sold in Europe are on average 45 percent more fuel-efficient compared to the same vehicle category sold in the US (IEA 2021). As such, US households do not necessarily benefit from lower gasoline taxation in terms of household expenditure on transport fuel. They are also more vulnerable to rapid increases in the price of crude oil. Having high gasoline tax rates thus reduces – rather than increases – the short run welfare impact on households. Hence, policymakers should resist the temptation to lower gasoline tax rates during the current energy crisis. With imposed tax cuts, households will, in the medium and long run, buy vehicles with higher fuel consumption and thus become more exposed to price surges in the future – again compelling policymakers to adjust tax rates, creating a downward spiral. Instead, alternative measures should be considered to alleviate the effects of the heavy price pressure on low-income households – for instance, revenue recycling of the carbon tax revenue and increased subsidies of public transport.
To reach environmental and climate goals, Sweden urgently needs to phase out the use of fossil fuels in the transport sector – Sweden’s largest source of carbon dioxide emissions. This is exactly what a gradual increase of the tax rate on gasoline and diesel would achieve. At the same time, it would benefit consumers by shielding them from the adverse effects of future oil price volatility.
The most common response from policymakers regarding fuel tax rates however goes in the opposite direction. In Sweden, the excise tax on gasoline and diesel was reduced by 1.80 SEK per liter in 2022 and the current government plans to further reduce the price by easing the biofuel mandate. Similar tax cuts have been implemented in a range of European countries. Therefore, the distinguishing factor in the current situation lies in the exceptional responses from policymakers, rather than in the gasoline costs that households are encountering.
Gasoline Price Swings and Their Consequences for Georgian Consumers
The energy crisis that begun in 2021 has also made its mark on Georgia, where the operational expenses of personal vehicles, encompassing not only gasoline costs but also maintenance expenses, account for more than 8 percent of the consumer price index. The rise in gasoline prices sparked public protest and certain opposition parties proposed an excise tax cut to mitigate the gasoline price surge. In Georgia, gasoline taxes include excise taxes and VAT. Until January 1, 2017, the excise tax was 250 GEL per ton (9 cents/liter), it has since increased to 500 GEL (18 cents/liter). Despite protests and the suggested excise tax reduction, the Georgian government chose not to implement any tax cuts. Instead, it initiated consultations with major oil importers to explore potential avenues for reducing the overall prices. Following this, the Georgian National Competition Agency (GNCA) launched an inquiry into the fuel market for motor vehicles, concluding a manipulation of retail prices for gasoline existed (Georgian National Competition Agency, 2023).
The objective of this part of the policy paper is to address two interconnected questions. Firstly, are Georgian households affected by gasoline price increases? And secondly, if they are, is there a need for government intervention to mitigate the negative impact on household budgets caused by the rise in gasoline prices?
The Gasoline Market in Georgia
Georgia’s heavy reliance on gasoline imports is a notable aspect of the country’s energy landscape. The country satisfies 100 percent of its gasoline needs with imports and 99 percent of the fuel imported is earmarked for the road vehicle transport sector. Although Georgia sources its gasoline from a diverse group of countries, with nearly twenty nations contributing to its annual gasoline imports, the supply predominantly originates from a select few markets: Bulgaria, Romania, and Russia. In the last decade, these markets have almost yearly accounted for over 80 percent of Georgia’s total gasoline imports. Furthermore, Russia’s share has substantially increased in recent years, amounting to almost 75 percent of all gasoline imports in 2023. The primary reason behind Russia’s increased dominance in Georgia’s gasoline imports is the competitive pricing of Russian gasoline, which between January and August in 2023 was almost 50 percent cheaper than Bulgarian gasoline and 35 percent cheaper than Romanian gasoline (National Statistics Office of Georgia, 2023). Given the dominance of Russian gasoline in Georgia, the end-user (retail) prices of gasoline in Georgia, are closer to gasoline prices in Russia than EU gasoline prices (see Figure 1).
Figure 1. End-user Gasoline Prices in Georgia, Russia and the EU, 2013-2022.
Source: International Energy Agency, 2023.
However, while the gasoline prices increased steadily in 2020-2022 in Russia, gasoline prices in Georgia increased sharply in the same period. This more closely replicated the EU price dynamics rather than the Russian one. The sharp price increase in gasoline raised concerns from the Georgian National Competition Agency (GNCA). According to the GNCA one possible reason behind the sharp increase in gasoline prices in Georgia could be anti-competitive behaviour among the five major companies within the gasoline market. Accordingly, the GNCA investigated the behaviour of major market players during the first eight months of 2022, finding violations of the Competition Law of Georgia. Although the companies had imported and were offering consumers different and significantly cheaper transport fuels compared to fuels of European origin, their retail pricing policies were identical and the differences in product costs were not properly reflected in the retail price level. GNCA claims the market players coordinated their actions, which could have led to increased gasoline prices in Georgia (National Competition Agency of Georgia. (2023).
Given that increased gasoline prices might lead to increased household expenditures for fuel, it is important to assess the potential impact of recent price developments on household’s budgets.
Exploring Gasoline Price Impacts
Using data from the Georgian Households Incomes and Expenditures Survey (National Statistics Office of Georgia, 2023), weekly household expenditures on gasoline and corresponding weekly incomes were computed. To evaluate the potential impact of rising gasoline prices on households, the ratio of household expenditures on gasoline to household income was used. The ratios were calculated for all households, grouped in three income groups (the bottom 10 percent, the top 10 percent and those in between), over the past decade (see Figure 2).
Figure 2. Expenditure on Gasoline as Share of Income for Different Income Groups in Georgia, 2013-2022.
Source: National Statistics Office of Georgia, 2023.
Figure 2 shows that between 2013 and 2022, average households allocated 9-14 percent of their weekly income to gasoline purchases. There is no discernible increase in the ratio following the energy crisis in 2021-2022.
Considering the different income groups, the upper 10 percent income group experienced a slightly greater impact from the recent rise in gasoline prices (the ratio increased), compared to the overall population. For the lower income group, which experienced a rise in the proportion of fuel costs relative to total income from 2016 to 2021, the rate declined between 2021 and 2022. Despite the decline in the ratio for the lower-level income group, it is noteworthy that the share of gasoline expenditure in the household budget has consistently been high throughout the decade, compared to the overall population and the higher-level income group.
The slightly greater impact from the rise in gasoline prices for the upper 10 percent income group is driven by a 4 percent increase in nominal disposable income, paired with an 8 percent decline in the quantity of gasoline (Figure 3) in response to the 22 percent gasoline price increase. Clearly, for this income group, the increase in disposable income was not enough to offset the increase in the price of gasoline, increasing the ratio as indicated above.
For the lower 10 percent income group, there was a 23 percent increase in nominal disposable income, paired with a 9 percent decline in the quantity of purchased gasoline (Figure 3) in response to the 22 percent gasoline price increase . Thus, for this group, the increase in disposable income weakened the potential negative impact of increased prices, eventually lowering the ratio.
Figure 3. Average Gasoline Quantities Purchased, by Household Groups, per Week (In Liters) 2013-2022.
Source: National Statistics Office of Georgia, 2023.
The Georgian energy market is currently fully dependent on imports, predominantly from Russia. While sharp increases in petrol prices have been observed during the last 2-3 years, they do not seem to have significantly impacted Georgian households’ demand for gasoline. Noteworthy, the lack of impact from gasoline price increases on Georgian households’ budgets, as seen in the calculated ratio (depicted in Figure 2), can be explained by the significant rise in Georgia’s imports from the cheap Russian market during the energy crisis years. Additionally, according to the Household Incomes and Expenditures survey, there was in 2022 an annual increase in disposable income for households that purchased gasoline. However, the data also show that low-income households spend a high proportion of their income on gasoline.
Although increased prices did not significantly affect Georgian households, the extremely high import dependency and the lack of import markets diversification poses a threat to Georgia’s energy security and general economic stability. Economic dependency on Russia is dangerous as Russia traditionally uses economic relations as a lever for putting political pressure on independent economies. Therefore, expanding trade and deepening economic ties with Russia should be seen as risky. Additionally, the Russian economy has, due to war and sanctions, already contracted by 2.1 percent in 2022 and further declines are expected (Commersant, 2023).
Prioritizing actions such as diversifying the import market to find relatively cheap suppliers (other than Russia), closely monitoring the domestic market to ensure that competition law is not violated and market players do not abuse their power, and embracing green, energy-efficient technologies can positively affect Georgia’s energy security and positively impact sustainable development more broadly.
Fueling Concerns: The True Cost of Transportation in Latvia
In May 2020, as the Latvian Covid-19 crisis began, Latvia’s gasoline price was 0.99 EUR per liter. By June 2022, amid the economic effects from Russia’s war on Ukraine, the price had soared to a record high 2.09 EUR per liter, sparking public and political debate on the fairness of fuel prices and potential policy actions.
While gas station prices are salient, there are several other more hidden factors that affect the real cost of transportation in Latvia. This part of the policy paper sheds light on such costs by looking at some of its key indicators. First, we consider the historical price of transport fuel in Latvia. Second, we consider the cost of fuel in relationship to average wages and the fuel type composition of the vehicle fleet in Latvia.
The Price of Fuel in Latvia
Latvia’s nominal retail prices for gasoline (green line) and diesel (orange line) largely mirror each other, though gasoline prices are slightly higher, in part due to a higher excise duty (see Figure 1). These local fuel prices closely follow the international oil market prices, as illustrated by the grey line representing nominal Brent oil prices per barrel.
The excise duty rate has been relatively stable in the past, demonstrating that it has not been a major factor in fuel price swings. A potential reduction to the EU required minimum excise duty level will likely have a limited effect on retail prices. Back of the envelope calculations show that lowering the diesel excise duty from the current 0.414 EUR per liter to EU’s minimum requirement of 0.33 EUR per liter could result in approximately a 5 percent drop in retail prices (currently, 1.71 EUR per liter). This at the cost of a budget income reduction of 0.6 percent, arguably a costly policy choice.
In response to recent years’ price increase, the Latvian government opted to temporarily relax environmental restrictions, making the addition of a bio component to diesel and gasoline (0.065 and 0.095 liters per 1 liter respectively) non-mandatory for fuel retailers between 1st of June 2022 until the end of 2023. The expectation was that this measure would lead to a reduction in retail prices by approximately 10 eurocents. To this date, we are unaware of any publicly available statistical analysis that verifies whether the relaxed restriction have had the anticipated effect.
Figure 1. Nominal Retail Fuel Prices and Excise Duties for Gasoline and Diesel in Latvia (in EUR/Liter), and Nominal Brent Crude Oil Prices (in EUR/Barrel), January 2005 to August 2023.
The True Cost of Transportation
Comparing fuel retail prices to average net monthly earnings gives insight about the true cost of transportation in terms of purchasing power. Figure 2 displays the nominal net monthly average wage in Latvia from January 2005 to June 2023 (grey line). During this time period the average worker saw a five-fold nominal wage increase, from 228 EUR to 1128 EUR monthly. The real growth was two-fold, i.e., the inflation adjusted June 2023 wage, in 2005 prices, was 525 EUR.
Considering fuel’s share of the wages; one liter of gasoline amounted to 0.3 percent of an average monthly wage in 2005, as compared to 0.12 percent in 2023, with diesel displaying a similar pattern. Thus, despite recent years’ fuel price increase, the two-fold increase in purchasing power during the same time period implies that current fuel prices may not be as alarming for Latvian households as they initially appeared to be.
Figure 2. Average Nominal Monthly Net Wages in Latvia and Nominal Prices of One Liter of Gasoline and Diesel as Shares of Such Wages (in EUR), January 2005 to June 2023.
Another factor to consider is the impact of technological advancements on fuel efficiency over time. The idea is simple: due to technological improvements to combustion engines, the amount of fuel required to drive 100 kilometers has decreased over time, which translates to a lower cost for traveling additional kilometers today. An EU average indicator shows that the fuel efficiency of newly sold cars improved from 7 liters to 6 liters per 100 km, respectively, in 2005 and 2019. While we lack precise data on the average fuel efficiency of all private vehicles in Latvia, we can make an informed argument in relation to the technological advancement claim by examining proxy indicators such as the type of fuel used and the average age of vehicles.
Figure 3 shows a notable change in the fuel type composition of the vehicle fleet in Latvia. Note that the decrease in the number of cars in 2011 is mainly due to a statistical correction for unused cars. At the start of the 21st century, 92 percent of Latvian vehicles were gasoline-powered and 8 percent were diesel-powered. By 2023, these proportions had shifted to 28 percent for gasoline and 68 percent for diesel. Diesel engines are more fuel efficient, usually consuming 20-35 percent less fuel than gasoline engines when travelling the same distance. Although diesel engines are generally pricier than their gasoline counterparts, they offer a cost advantage for every kilometer driven, easing the impact of rising fuel prices. A notable drawback of diesel engines however, is their lower environmental efficiency – highlighted following the 2015 emission scandal. In part due to the scandal, the diesel vehicles growth rate have dropped over the past five years in Latvia.
Figure 3. Number of Private Vehicles by Fuel Type and the Average Age of Private Vehicles in Latvia, 2001 to 2023.
Figure 3 also shows that Latvia’s average vehicle age increased from 14 years in 2011 to 15.1 years in 2023. This is similar to the overall EU trend, although EU cars are around 12 years old, on average. This means that, in Latvia, the average car in 2011 and 2023 were manufactured in 1997 and 2008, respectively. One would expect that engines from 2008 have better technical characteristics compared to those from 1997. Recent economic research show that prior to 2005, improvements in fuel efficiency for new cars sold in the EU was largely counterbalanced by increased engine power, enhanced consumer amenities and improved acceleration performance (Hu and Chen, 2016). I.e., cars became heavier, larger, and more powerful, leading to higher fuel consumption. However, after 2005, cars’ net fuel efficiency started to improve. As sold cars in Latvia are typically 10-12 year old vehicles from Western European countries, Latvia will gradually absorb a more fuel-efficient vehicle fleet.
The increase of purchasing power, a shift to more efficient fuel types and improvements in engine efficiency have all contributed to a reduction of the overall real cost of transportation over time in Latvia. The recent rise in fuel prices to historically high levels is thus less concerning than it initially appears. Moreover, a growing share of cars will not be directly affected by fuel price fluctuations in the future. Modern electric vehicles constitute only 0.5 percent of all cars in Latvia today, however, they so far account for 10 percent of all newly registered cars in 2023, with an upward sloping trend.
Still, politicians are often concerned about the unequal effects of fuel price fluctuations on individuals. Different car owners experience varied effects, especially when considering factors like income and location, influencing transportation supply and demand.
First, Latvia ranks as one of the EU’s least motorized countries, only ahead of Romania, with 404 cars per 1000 inhabitants in 2021. This lower rate of vehicle ownership is likely influenced by the country’s relatively low GDP per capita (73 percent of the EU average in 2022) and a high population concentration in its capital city, Riga (32 of the population lives in Riga city and 46 percent in the Riga metropolitcan area). In Riga, a developed public transport system reduces the necessity for personal vehicles. Conversely, areas with limited public transport options, such as rural and smaller urban areas, exhibit a higher demand for personal transportation as there are no substitution options and the average distance travelled is higher than in urban areas. Thus, car owners in these areas tend to be more susceptible to the impact of fuel price volatility.
Second, Latvia has a high Gini coefficient compared to other EU countries, indicating significant income inequality (note that the Gini coefficient measures income inequality within a population, with 0 representing perfect equality and 1 indicating maximum inequality. In 2022, the EU average was 29.6 while Latvia’s Gini coefficient was 34.3, the third highest in the EU). With disparities in purchasing power, price hikes tend to disproportionately burden those with lower incomes, making fuel more costly relative to their monthly wages.
These income and location factors suggest that inhabitants in rural areas are likely the most affected by recent price hikes. Distributional effects across geography (rural vs urban) are often neglected in public discourse, as the income dimension is more visible. But both geography and income factors should be accounted for in a prioritized state support, should such be deemed necessary.
- Commersant. (2023). Economic dependence on Russia is growing rapidly – reasons and risks. Commersant.
- Drivkraft Sverige. (2023). Drivkraft Sverige: Data Set. drivkraftsverige.se/statistik/priser/bensin/
- Hu, K. and Chen, Y. (2016). Technological growth of fuel efficiency in European automobile market 1975–2015. Energy Policy, 98, pp.142-148.
- IEA. (2021). Fuel Consumption of Cars and Vans. Tracking Report. International Energy Agency.
- International Energy Agency. (2023). End-Use Prices Data Explorer. https://www.iea.org/data-and-statistics/data-tools/end-use-prices-data-explorer?tab=Overview
- National Competition Agency of Georgia. (2023). Regarding the investigation carried out in accordance with the order of the Chairman of the National Competition Agency of Georgia dated August 16, 2022 N04/165.
- National Statistics Office of Georgia. (2023). External Trade Portal. Retrieved from https://ex-trade.geostat.ge/en
- National Statistics Office of Georgia. (2023). Households Incomes and Expenditures Survey. https://www.geostat.ge/en/modules/categories/128/databases-of-2009-2016-integrated-household-survey-and-2017-households-income-and-expenditure-survey
- Sgaravatti, G., Tagliapietra, S., & Zachmann, G. (2022). National policies to shield consumers from rising energy prices. Bruegel Datasets.
- Statistics Sweden. (2023). Average hourly wage statistics. http://www.statistikdatabasen.scb.se
- Trafikverket. (2023). Vägtrafikens utsläpp 2022. Technical report. Swedish Transport Administration.
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.
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.
Throughout 2022, the reduction in Russian gas imports to the EU and the resilience of European energy markets have been subject of significant public discourse and policy-making. Of particular concern has been the EU’s ability to maintain its environmental goals, as substitution from Russian pipeline gas to liquified natural gas and other fuels such as coal, could result in increased emissions. This brief aims to reevaluate the consequences from the loss of Russian gas and the EU’s response to it on greenhouse gas emissions in the region. Our analysis suggests that the energy crisis did not result in a rise in emissions in 2022. While some of the factors that contributed to this outcome – such as a mild winter – may have been coincidental, the adjustments caused by the 2022 gas squeeze are likely to support rather than jeopardize the EU’s green transition.
Energy markets in Europe experienced a tumultuous 2022, with the Russian squeeze on natural gas exported to the region bringing a major shock to its energy supply. Much attention has been devoted to the effects of the succeeding spiking and highly fluctuating energy prices on households’ budget and on the production sector, with numerous policy initiatives aimed at mitigating these effects (see, e.g., Reuters or Sgaravatti et al., 2021). Another widely discussed concern has revolved the consequences of the gas crisis – such as switching to coal – on the EU’s climate policy objectives (see e.g. Bloomberg or Financial Times). In this brief, we analyze and discuss to what extent this concern turned out to be valid, now that 2022 has come to an end.
We consider greenhouse gas (GHG) emissions stemming from the main strategies that allowed the EU to weather the gas crisis throughout 2022 – namely the substitution from Russian gas to other energy sources. These strategies include increased imports of liquified natural gas (LNG), a lower gas demand, and an increased reliance on coal, oil, and other energy sources. We also discuss the implications of the crisis for climate mitigation in the EU and try to draw lessons for the future.
Substitution to LNG and Pipeline Gas from Other Suppliers
Prior to 2022, Russian natural gas largely reached Europe by pipeline (92.4 percent in 2021 according to Eurostat). More than half of these pipeline imports, 86 billion cubic meters (bcm), were lost during the 2022 Russian gas supply squeeze, predominantly through the shut-down of both the Yamal and the Nordstream pipelines. 57 percent of this “missing” supply was met through an increase in LNG imports from several countries, the largest contributor being the U.S. Another 27 percent of the “missing Russian gas” was substituted by an increase in pipeline gas imports from other suppliers, with the UK (20 percent) and Norway (7 percent) taking the lead. A substantial part of the replaced gas was stored, rather than combusted. With this in mind, here we concentrate on the upstream emissions associated with this change – i.e., emissions that occurred during the extraction, processing, and transportation. The change in the combustion emissions is postponed to the next section.
There is an ongoing debate in the literature on whether the greenhouse gas pollution intensity of LNG is higher or lower than that of gas delivered through pipelines – prior to final use. In comparison to pipeline gas, LNG is associated with emissions resulting from energy-intensive liquefaction and regassification processes in upstream operations as well as with fuel combustion from transportation on ocean tankers. For both LNG and pipeline gas it is also crucial to consider fugitive methane emissions, as methane has up to 87 times greater global warming potential than carbon dioxide in the first 20 years after emission, and up to 36 times greater in the first 100 years. One source of methane emissions is leaks from the natural gas industry (both “intentional” and accidental) since methane is the primary component of natural gas. Both LNG and pipeline gas infrastructure are subject to such leaks, and the size and frequency of these leaks during transportation varies greatly depending on the technologies used, age of infrastructure, etc. Further, the risk of these leaks may also be different depending on the technology of gas extraction.
Currently there is limited knowledge about the size of greenhouse gas emissions, including methane emissions resulting from leaks, from specific gas projects. Until recently, most estimates were based partially on self-reported data and partially on “emission factors” data. Modern and more reliable methods, for instance satellite-based measures for methane emissions, suggest that the resulting figures are greatly underestimated (see, e.g., Stern, 2022; IEA; ESA) but the coverage of these new estimates is currently limited.
As a result, there is considerable disagreement in the literature on the emissions arising from Russian pipeline gas imports vs. LNG imports to the EU. For example, Rystad (2022) argues that the average LNG imports to Europe have a CO2 emission intensity that is more than 2.5 times higher than that from pipeline gas from Russia (although they do not explicitly state whether these figures include fugitive methane emissions). On the contrary, Roman-White et al. (2019) suggest that the life-cycle GHG emission intensity of EU LNG imports (from New Orleans) is lower than EU gas imports from Russia (via the Yamal pipeline).
For the purposes of this exercise, we choose to rely on middle-ground estimates by DBI and Sphera, which assess GHG emission intensity along different Russian gas import routes (DBI, 2016) and across different LNG suppliers to the EU (Thinkstep – Sphera, 2020). This allows us to account for substantial heterogeneity across routes.
We also account for the change in upstream emissions associated with the switch from imports of pipeline Russian gas to pipeline gas imports from Norway and the UK. For this, we approximate the GHG emission intensity of the new flows using the estimate suggested by Thinkstep – Sphera (2017).
The results of our assessment are presented in the top three rows of Table 1. They suggest that a substitution from Russian gas imports to LNG imports and pipeline imports from other sources resulted in an increase in upstream GHG emissions by approximately 14 million tons (Mt) of CO2eq. Details on calculations and assumptions are found in the online Appendix.
Table 1. Change in EU GHG emissions resulting from Russian gas squeeze.
The Decline in Gas Demand and the Switch to Other Fuels
A decrease in gas use in the EU constituted another response to the Russian gas squeeze. Gas demand in the EU is estimated to have declined by 10 percent (50 bcm or 500 TWh) in 2022 with respect to 2021 (IEA, 2022). Part of this decline was facilitated by switching from gas to other polluting fuels, such as oil and coal. The extent to which switching occurred however differed across the three main uses of gas; power generation, industrial production, and residential and commercial use. Below we discuss them separately.
At the onset of the 2022 energy crisis, a prevalent expectation was that there would be significant gas-to-coal switching in power generation. However, gas demand for power generation, which accounts for 31.4 percent of the gas demand from EU countries (European Council), increased by only 0.8 percent in 2022 (EMBER, 2022, p.29), implying that there was no direct substitution from gas-fired to coal-fired generation.
One of the reasons to why there was no major switching to coal in spite of the increase in gas prices is that CO2 emissions are priced in the Emissions Trading System (ETS) program, and the average carbon price has been growing recently, reaching an average of around €80/ton in 2022. Given that coal has a higher emission intensity than gas, the carbon price increases the relative cost of coal versus gas for power generators.
Instead, the decline in demand came from industry, residential and commercial use, which together account for nearly 57 percent of the EU’s gas demand (European Council).
For the industry, IEA calculations (2022) suggest a demand drop of 25 bcm, which would correspond to approximately 50 Mt CO2eq. However, half of the industrial gas reduction came from gas to oil switching. Based on our estimates, this switch implies an additional 41 Mt CO2eq emissions, considering both upstream emissions and emissions from use in furnaces (assuming this to be the prevalent use of the oil that substituted gas, see McWilliams et al., 2023). The remaining half of the industrial demand decline resulted from energy-efficiency improvements, lower output, and import of gas-intensive inputs where possible (ibid.). These changes are either neutral in terms of life-cycle emission impact (import increases) or emission-reducing (efficiency improvements and lower output).
Residential and Commercial Use
Residential and commercial use represented the remaining part of the 500 TWh gas demand decline. In this case, lower gas demand is unlikely to imply massive fuel switching to other fossil fuels, simply because of the lack of short-term alternatives. For example, European households use gas mostly for space heating and cooking, and albeit both higher use of coal for home-heating (BBC) and a surge in installations of heat pumps (Bruegel, 2023 and EMBER, 2023) have been reported, the net change in emissions resulting from these two opposite developments is likely relatively minor as compared to other considered sizeable changes.
The Rise of Coal
As observed, there was no direct switch from gas to coal in European power generation. However, coal generation in the EU did increase by 6 percent in 2023 (IEA, 2022), to help close the gap in electricity supply created by the temporary shut-down of nuclear plants in France and the reduced performance of hydro. In our calculations we assume that in a counterfactual world with no Russian gas squeeze, gas-fired electricity would have covered most of the gap that was instead covered by coal. Therefore, we estimate that, as an indirect result of the Russian gas squeeze in 2022, CO2eq emissions increased by 27 Mt, specifically because of the ramp-up in coal generation (see the second section in Table 1).
Gas Shortage and the EU’s Climate Objectives
In recent years, the EU has made substantial progress in climate change mitigation. Despite widely expressed concerns, it achieved its 2020 targets – reducing emission by 20 percent by 2020, from the 1990 level. However, its current target of a 55 percent net GHG emission reduction by 2030, requires average yearly cuts of 134 Mt CO2eq, from the 2021 level. This is an ambitious target: while the emission cut between 2018 and 2019 exceeded this level, the average yearly cut between 2018 and 2021 however fell short (Eurostat).
The question is if the Russian gas squeeze can significantly undermine the EU’s ability to achieve these climate goals?
First, based on our assessment above, the changes prompted by the Russian squeeze – namely a move from pipeline-gas to LNG, a decline in gas demand and an increase in coal and oil use – made 2022 emissions decline by 18 Mt CO2eq. This suggests that the energy shock prompted overall emission-reducing adjustments in the short run. One important question that arises from this is therefore how permanent these adjustments are.
The increased reliance on LNG (and other gas suppliers) is likely to be permanent as a return to imports from Russia is hardly imaginable and as the 2022 surge in LNG imports entailed significant investments and contractual obligations. According to our estimates, overall, this shift is going to cause a relatively modest increase in yearly CO2eq emissions, approximately 10 percent of the needed emission reduction outlined above. Moreover, this is accounting for emissions throughout the EU’s entire supply chain – which is increasingly advocated for, but not currently applied in the typical emission accounting. It is, of course, important to make sure that ongoing LNG investments do not result in “carbon lock-ins”, postponing the green transition.
The decline in gas demand is a welcome development for climate mitigation if it is permanent. Part of the decline, from improved energy efficiency or installation of heat pumps, is indeed permanent. However, European households also responded temporarily (to warmer than usual winter and high gas prices (for instance by reducing their thermostats). Their behavior in the near future will therefore depend on the development of both these variables.
Overall, our assessment is that the Russian gas squeeze did force some adjustments in demand that might translate into a permanent decline in greenhouse gas emissions.
The question however remains of how the shortage of gas can be met in a scenario with higher gas demand due to, for instance, colder winters. In terms of climate objectives, it is of paramount importance that coal-powered generation does not increase (which would happen if, for instance, the price of gas continues to raise due to shortages). In this sense some lessons can be learned from the response to the shortage in electricity supply following the exceptional under-performance of nuclear and hydro in 2022. Wind and solar, which provide the lowest-cost source of new electricity production, in combination with declines in electricity demand, were able to cover 5/6 of the 2022 shortage created by the nuclear and hydro shock (EMBER, 2023), thus relegating coal to a residual contribution. We expect this pattern to emerge also in the future in the presence of other crises. However, we also caution that the lower production of electricity was at least partially caused by the dramatic heatwaves and droughts experienced throughout the summer in Europe. These events are likely to happen more often in the face of climate change. European policy-makers should therefore carefully assess the capacity of the EU energy system to address potentially multiple and frequent shocks with minimal to no-reliance on coal, in a scenario where also reliance on gas needs to be in constant decline given the Russian gas squeeze and unreliability.
Finally, the dramatic circumstances of 2022 led the EU to adopt the REPowerEU plan, which outlines financial and legal measures to, among other things, speed up the development of renewable energy projects and induce energy-saving behavior.
The outlined observations lead us to conclude that the Russian gas squeeze is ultimately unlikely to sizably reduce the chances of the EU reaching its climate goals, suggesting that the 2022 concerns in this regard were somewhat exaggerated. Nonetheless, learning from the costly lessons of the 2022 energy crisis is crucial for efficient policy making in the future.
- BBC. (2022, September 29). Energy prices: Households turning to coal ahead of ‘hard winter’. https://www.bbc.com/news/uk-england-somerset-63072561
- Bloomberg. (2022, July 22). Putin’s War Threatens Europe’s Ambitious Climate Goals. https://www.bloomberg.com/news/articles/2022-07-07/ukraine-invasion-threatens-europe-s-climate-change-goals#xj4y7vzkg
- DBI. (2016). Critical Evaluation of Default Values for the GHG Emissions of the Natural Gas Supply Chain. https://www.dbi-gut.de/emissions.html?file=files/PDFs/Emissionen/Report_english.pdf&cid=5808
- EMBER. (2023). European Electricity Review 2023. https://ember-climate.org/insights/research/european-electricity-review-2023/#supporting-material-downloads
- ESA. (2020). Mapping methane emissions on a global scale. https://www.esa.int/Applications/Observing_the_Earth/Copernicus/Sentinel-5P/Mapping_methane_emissions_on_a_global_scale
- European Commission. (2022). REPowerEU: affordable, secure and sustainable energy for Europé. https://commission.europa.eu/strategy-and-policy/priorities-2019-2024/european-green-deal/repowereu-affordable-secure-and-sustainable-energy-europe_en
- European Council. (2023). Infographic – Where does the EU’s gas come from? https://www.consilium.europa.eu/en/infographics/eu-gas-supply/#:~:text=Gas%2520consumption%2520in%
- Eurostat. (2023). https://ec.europa.eu/eurostat/databrowser/view/ENV_AC_AIGG_Q/default/table?lang=en&category=env.env_air.env_air_aa
- Financial Times. (2020, June 20). EU Warns against Fossil Fuel ‘Backsliding’ as Coal Replaces Russian Gas. https://www.ft.com/content/a8b179e2-b565-42b6-bb41-90aea44536e1.
- ICAP. (2023). ICAP Allowance Price Explorer. https://icapcarbonaction.com/en/ets-prices
- IEA. (2020). Global methane emissions from oil and gas. https://www.iea.org/articles/global-methane-emissions-from-oil-and-gas
- IEA. (2022). “How to Avoid Gas Shortages in the European Union in 2023”, https://www.iea.org/reports/how-to-avoid-gas-shortages-in-the-european-union-in-2023
- IEA. (2023). Electricity Market Report 2023. https://www.iea.org/reports/electricity-market-report-2023
- McWilliams, B., Sgaravatti, G. and Zachmann, G. (2021). European natural gas imports. Bruegel Datasets, first published 29 October, available at https://www.bruegel.org/publications/datasets/european-natural-gas-imports/
- McWilliams, B., Tagliapietra, S., Zachmann, G. and Deschuyteneer. T. (2023). Preparing for the next winter: Europe’s gas outlook for 2023. Policy Brief 01/2023, Bruegel. https://www.bruegel.org/policy-brief/european-union-gas-survival-plan-2023
- Reuters. (2023, February 13). Europe’s spend on energy crisis nears 800 billion euros. https://www.reuters.com/business/energy/europes-spend-energy-crisis-nears-800-billion-euros-2023-02-13/
- Roman-White, S., Rai, S., Littlefield, J., Cooney, G. and Skone, T. J. (2019). Life cycle greenhouse gas perspective on exporting liquefied natural gas from the United States: 2019 update. DOE/NETL-2019/2041. National Energy Technology Laboratory. https://www.energy.gov/sites/prod/files/2019/09/f66/2019%20NETL%20LCA-GHG%20Report.pdf
- Rystad. (2022). LNG import boom could drive up European emissions by 35 million tonnes. Rystad Energy.
- Sgaravatti, G., Tagliapietra, S., Trasi, C. and Zachmann, G. (2021). National policies to shield consumers from rising energy prices. Bruegel Datasets. https://www.bruegel.org/dataset/national-policies-shield-consumers-rising-energy-prices
- Thinkstep – Sphera. (2017). Greenhouse Gas Intensity of Natural Gas. http://gasnam.es/wp-content/uploads/2017/11/NGVA-thinkstep_GHG_Intensity_of_NG_Final_Report_v1.0.pdf
- Thinkstep – Sphera. (2020). Life Cycle Emissions of Natural Gas Transported via TurkStream. https://energijabalkana.net/wp-content/uploads/2021/10/ts-Sphera-LCA-TurkStream_Final-Report.pdf
- Stern, J. P. (2022). Measurement, Reporting, and Verification of Methane Emissions from Natural Gas and LNG trade: Creating transparent and credible frameworks, OIES Paper: ET, No. 06, ISBN 978-1-78467-191-4, The Oxford Institute for Energy Studies, Oxford.
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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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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Oil majors often choose to operate in countries with weak property rights. This may appear surprising, since the lack of constraints on governments may create incentives to renege on initial promises with firms and renegotiate tax payments once investments have occurred and, in the worst case, expropriate the firm. In theory, backloading investments, production and tax payments may be used to create self-enforcing agreements which do not depend on legal enforcement. Using a new dataset covering the universe of oil majors’ assets that started production between 1974 and 1999, we indeed show in a recent CEPR Working Paper (Paltseva, Toews, and Troya-Martinez, 2022) that investments, production and tax payments are delayed by two years in countries with weak institutions relative to countries with strong institutions. Extending the dataset back to 1960 and exploiting the transition to a new world oil order where expropriation became easier, allows us to interpret our estimates as causal. In particular, prior to the transition expropriations were not feasible, due to the omnipresent and credible military threat imposed by the oil majors’ countries of origin. As the new order sat in, a new equilibrium emerged, in which expropriations became a feasible option. This transition incited an increase in expropriations and forced firms to adjust to the new reality by backloading contracts.
The Hold-up Problem
In December of 2006, when the oil price was climbing towards new heights, the Guardian reported that the Russian government was about to successfully force Shell into transferring their controlling stake in a huge liquified gas project back into the hands of the government. While officially this was motivated by environmental concerns surrounding the Sakhalin-II project, most observers agreed that this might be considered a textbook example of the hold-up problem faced by oil firms when investing in countries with limited constraints on the executive. At its core, the hold-up problem refers to the idea that the government may renege on the initial promise and appropriate a bigger share of the pie once investments have been made. Obviously, this is not an oil-specific issue and concerns any type of investment in countries with weak property rights. Academics, who worked on resolving these issues, suggest the use of self-enforcing agreements (Thomas and Worrall, 1994). These agreements use future gains from trade (as opposed to third-party enforcement) to incentivize the governments not to expropriate. And while the theoretical literature has prolifically developed over the last 30 years (Ray, 2002), to the best of our knowledge no empirical evidence has been provided on the use and dynamic patterns of self-enforcing backloaded contracts.
Data and Sample
In Paltseva, Toews and Troya-Martinez (2022), we rely on micro-level data on oil and gas projects provided by Rystad Energy, an energy consultancy based in Norway. Its database contains current and historical data on physical, geological and financial features for the universe of oil and gas assets. We focus on the assets owned by the oil majors (BP, Chevron, ConocoPhilips, Eni, ExxonMobile, Shell, and Total) using all assets that started production between 1960 and 1999, leaving us with a total of 3494 assets. An asset represents a production site with at least one well, operated by at least one firm, and with the initial property right being owned by at least one country. Being able to conduct the analysis on the asset level is particularly valuable since it allows us to control for a large number of confounding factors and rule out several alternative explanations of our main finding.
Moreover, there are three advantages of focusing our analysis on the oil and gas sector in general and the oil majors in particular. First, the sunk investments in the development of oil and gas wells are enormous, making the hold-up problem in the oil sector particularly severe. Second, oil majors have been around for many years since all of them were created before WWII. This provides us with a sufficiently long horizon to capture backloading over time. Third, the majors are simultaneously investing in many countries which provides us the necessary cross-sectional variation in institutional quality. To differentiate between countries with weak and strong institutions, we use a specific dimension from the Polity IV dataset measuring the constraints on the executive. The location of all the assets disaggregated by firm as well as a binary distinction in a country’s institutional quality is shown in Figure 1.
Figure 1. Spatial distribution of assets and institutional quality
A Stylized Fact
For the empirical analysis, our variables of interest are investment, production and tax payments normalized by the respective asset-specific cumulative sum over a period of 35 years. The resulting cumulative shares are depicted in Figure 2. We focus on physical production which, in addition to being considered the most reliable measure of an asset’s activity, does not require discounting. Real values of investment and tax payment depict a very similar picture. Most importantly, the dashed lines illustrate that 2/3 of cumulative production shares are reached approximately two years earlier in countries with strong institutions, in comparison to countries with weak institutions. The average asset size does not differ significantly between these groups. Such delays are costly for countries with weak institutions. Our back-of-the-envelope calculation suggests that the average country loses around 120 million US$ per year due to the delayed production and the respective tax payments. We confirm that the two-year delay cannot be explained by geographical, geological or financial confounders such as the location of the well, fuel type or contract features.
Figure 2. Years to reach 66% of cumulative flows in 35 years
The Transition to a New World Order
To push towards a causal interpretation of the results, we exploit the global transition to a new world oil order. This change affected the probability of expropriations in countries with weak institutions while leaving countries with strong institutions unaffected. In particular, the post-WWII weakening of the OECD members as political and military actors provides a natural experiment of global proportions. Expropriations are first viewed as impossible due to the military threat of British, French and US armies, and then become possible due to a global movement aiming at returning sovereignty over natural resources to the resource-rich economies. In the words of Daniel Yergin (1993): “The postwar petroleum order in the Middle East had been developed and sustained under American-British ascendancy. By the latter half of the 1960s, the power of both nations was in political recession, and that meant the political basis for the petroleum order was also weakening. […] For some in the developing world […] the lessons of Vietnam were […] that the dangers and costs of challenging the United States were less than they had been in the past, certainly nowhere near as high as they had been for Mossadegh, [the Iranian politician challenging UK and US before the coup d’etat in 1953], while the gains could be considerable.” Consequently, the number of expropriations has grown substantially since 1968, marking the transition to a new world order (Figure 3). However, Kobrin (1980) finds that even during the peak of expropriations in 1960-1976, only less than 5 % of all foreign-owned firms in the developing countries were expropriated. We suggest that this is, at least partly, thanks to the use of backloaded self-enforcing contracts.
Figure 3. Transition to a new world order
Indeed, focusing on the years around the transition to the new world oil order, we show that there have not been any differences in investment, production or tax payments dynamics between countries with weak and strong institutions in the early years of the 1960s. But investment, production and the payments of taxes started experiencing significant delays after 1968 in the countries with weak institutions, using countries with strong institutions as a control. Intuitively, the omnipresence of a credible military threat in response to an expropriation served as an effective substitute for strong local formal institutions and eliminated the need for contracts to be self-enforced and backloaded in countries with weak institutions. Once this threat disappeared, contracts had to be self-enforcing and investment, production and tax payments had to be backloaded to decrease the risk of being expropriated by the governments of resource-rich economies. Theoretically, these initial differences in contract backloading between countries with strong and weak institutions should disappear in the long run, because the future gains from trade need to materialize eventually. We confirm empirically that this point is reached on average 20 years after firms start a contractual relationship with a country.
We provide evidence that oil firms seem to backload contracts in countries with weak institutions. We show that such backloading appears in the data during the transition to a new world order since 1968, when firms were in need of a new mechanism to deal with weak property rights and the risk of expropriations. We estimate the cost of such delays to be around 120 US$ per country and year. While this cost is high, it is important to emphasize that in the absence of such backloading, forward-looking CEOs of oil majors would often choose not to invest in the first place, since they would anticipate the severe commitment problems (Cust and Harding, 2020). Thus, as a second-best, the cost of the backloading may be marginal compared to the value added from trade when oil majors are willing to invest in countries with weak institutions and questionable property rights.
- Cust, J. & Harding, T. (2020). “Institutions and the location of oil exploration”. Journal of the European Economic Association, 18(3): 1321–1350.
- Kobrin, S. J. (1980). “Foreign enterprise and forced divestment in LDCs”. International Organization, 65–88.
- Kobrin, S. J. (1984). “Expropriation as an attempt to control foreign firms in LDCs: trends from 1960 to 1979.” International Studies Quarterly, 28(3): 329–348.
- Paltseva, E, Toews, G & Troya Martinez, M. (2022). ‘I’ll pay you later: Relational Contracts in the Oil Industry‘. London, Centre for Economic Policy Research.
- Debraj, R. (2002). “The time structure of self-enforcing agreements.” Econometrica, 70(2): 547–582.
- Jonathan, T. & Worrall, T. (1994). “Foreign direct investment and the risk of expropriation.” The Review of Economic Studies, 61(1): 81–108
- Yergin, D. (2011). The prize: The epic quest for oil, money & power. Simon and Schuster.
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/
With an increasing world demand for energy and a growing pressure to reduce carbon emissions to slow down global warming, there is a growing necessity to develop new technologies that would help addressing demand and carbon footprint issues. However, taking into account the world’s dependence on hydrocarbons the question remains – can new technologies actually change the energy markets? In this policy brief, we highlight challenges and opportunities that new technologies will bring for energy markets, in particular wind energy, smart grid technology, and electromobility, that were discussed during the 10th SITE Energy Day, held at the Stockholm School of Economics on October 13, 2016.
The expanding world population and economic growth are considered the main drivers of the global energy demand. Up to 2040, total energy use is estimated to grow by 71% in developing countries and by 18% in the more mature energy-consuming OECD economies (IEA, 2016). In parallel, many countries (including the world’s biggest economies and largest emitters: USA and China) have signed the Paris agreement – the first-ever universal, legally binding global climate deal that aims to reduce emissions and to keep the increase in global average temperature from exceeding 2°C above pre-industrial levels.
Meeting a growing global energy demand, and at the same time reducing CO2 emissions, cannot be achieved by practicing ‘business as usual’. It will require some fundamental changes in the way economic activity is organized. In this context, the development of new technologies and how it will affect the energy sector is a crucial element.
Wind power, smart grid, and electromobility
With technological progress and support schemes to decrease CO2 emissions, wind energy is now a credible and competing alternative to energy produced from coal, gas and oil. In 2015, wind accounted for 44% of all new power installations in the 28 EU member states, covering 11.4% of Europe’s electricity needs (see here).
This new technology has triggered a downward pressure on energy prices because of a “Merit order effect” (i.e. a displacement of expensive generation with cheaper wind). While consumers may appreciate this development, Ewa Lazarczyk Carlson, Assistant professor at the Reykjavik University (School of Business) and IFN, stressed that the increasing importance of wind energy challenges the functioning of electricity exchange. First, a lower price has reduced the incentives to invest in conventional power plants necessary when the wind is not blowing or when it is dark. Moreover, with the renewable energy intermittency, the probability of system imbalance and price volatility has increased. In turn, this has led to an increase of maintenance costs for conventional generators due to their dynamic generation costs (i.e. start-ups and shut-down costs).
Digital technology has gradually been used in the energy sector during the last decades, changing the way energy is produced and distributed. With smart grid (i.e. an electricity distribution system that uses digital information) energy companies can price their products based on real time costs while customers have access to better information, allowing them to optimize their energy consumptions. Sergey Syntulskiy, Visiting Professor at the New Economic School in Moscow, stressed that smart grids have had at least two effects. They have made the integration of renewable energy to the system easier and have allowed for prosumers, i.e. entities that both consume and produce energy. The next step is to develop new regulatory incentives to optimize energy systems as well as to provide a legal framework for the exchange of information in the energy sector.
One of the main pollutants has long been the transport sector that accounts for 26% energy-related of CO2 emission (IEA, 2016). Electromobility – that is, use of electric vehicles – is often considered the solution for this problem. When this technology is widely adopted, a major switch from oil to electricity is expected for the transportation sector. Mattias Goldmann, CEO of Fores, argued that even if electromobility will improve air quality and reduce noise levels in cities, its positive impact relies on smart grids and locally produced energy. Moreover, the environmental benefits will be ensured only if electric energy is produced from renewable and clean sources.
Toward a carbon-neutral energy system?
The Nordic countries are currently pushing for a near carbon-neutral energy system in 2050. Markus Wråke, CEO at the Swedish Energy Research Centre, emphasized that the Nordic Carbon-Neutral Scenario is only feasible if new technologies allow for a significant change of energy sources and a better interconnected market (see report by IEA 2016 b).
To cut emissions, a decrease in oil and gas consumption in energy production and within the transport sector is needed (see Figure 1). The adoption of electric vehicles (EVs) and hybrid cars is very likely to drastically increase in the next decades (EVs may have a share of 60% of the passenger vehicle stock in 2050, IEA 2016b).
Figure 1. Nordic CO2 emissions in the CNS
There are currently limited technology options to reduce emissions for big industrial energy consumers. Moreover, there is a concern that those industries may choose to relocate if the Nordic emission standards are too strict. It is therefore important to have low and stable electricity prices. This can only be achieved if cross-border exchanges are improved (which means that the electricity trade in the Nordic region will have to increase 4-5 times by 2050). It is unclear however how policy makers will create a regulation that incentivizes energy companies to build interconnections and increase trade both between the Nordic countries, and the Western and Eastern European countries.
Figure 2. Electricity trade 2015 and 2050
Another concern is that energy-exporting and energy-importing countries may have opposing attitudes towards investing and developing new energy technologies. Countries among the biggest energy producers and exporters depend on a stable demand and price for energy. For example, Russian GDP growth depends between 50-92% on the oil price, depending on the variables used for calculations, as mentioned by Torbjörn Becker, Director of SITE. For large exporters of hydrocarbon, new energy technologies may be seen as a threat because of a potentially reduced energy demand and an increased price volatility that will, in turn, create fundamental issues to balance state budgets and improve living standards.
Figure 3. The Relationship between Russian GDP and oil price
The challenge of security of supply
To summarize, new energy technologies will drive energy companies towards optimizations and cost cutting, bring previously unseen connectivity to energy markets and make energy markets more complex. Samuel Ciszuk, Principal Advisor at the Swedish Energy Agency, stressed that interconnected, more complex and interdependent energy systems might increase the vulnerability of energy systems to external threats and intimidates to decrease the security of supply. Technological change and increased competition with lower profit margins will force companies to minimize their expenditure on energy production, storage and transmission and to find cheaper financing options. Optimization and searches for cheaper financing instruments will push energy companies towards selling some of the company assets to financial investors. These changes will create a more decentralized energy market, with more players. Such energy systems will become harder to govern in times of an energy crisis and external threats. Policy makers will have to design new and more complex regulations to fit the needs of the transforming energy markets.
- Fogelberg, Sara and Ewa Lazarczyk, 2015. “Wind Power Volatility and the Impact on Failure Rates in the Nordic Electricity Market”, IFN Working Paper 1065.
- IEA, Annual Energy Outlook, 2016a.
- IEA/OECD/Norden, 2016b. “Nordic Energy Technology Perspectives” (see here)
- Speaker presentation from the 10th Energy day, 2016 (see here)