Russia’s invasion of Ukraine profoundly impacted the global economy, immediately sending shockwaves across the globe. The attack of a country that was once a major energy supplier to Europe on the country which was one of the top food exporters in the world, sent food and fuel prices spiralling, causing major energy shortages and the prospect of protracted recession in the United States and the European Union.
The unprovoked and brutal aggression resulted in nearly universal condemnation and widespread sanctions placed on Russia by the United States, the EU, and other Western allies. Financial sanctions were perhaps the most unexpected and significant with the potential for immediate impact on Russia’s neighbours, including those that did not formally join the sanctions regime. In addition to sanctions, the major consequence of the war was mass migration waves, particularly from Ukraine, but also from Russia and Belarus to neighbouring countries.
At the start of the war, it was expected that the Georgian economy would be severely and negatively impacted for the following reasons:
- First, as a former Soviet republic, Georgia historically maintained close economic trade ties with both Russia and Ukraine. The ties with Russia have weakened considerably in the wake of the 2008 Russo-Georgian war but remained significant. Russia was the primary market for imports of staple foods into Georgia, such as wheat flour, maize, buckwheat, edible oils, etc. Russia and Ukraine were both important export markets for Georgia. Russia was absorbing about 60 percent of Georgian wine exports and 47 percent of mineral water exports, while Ukraine was one of the leading importers of alcohol and spirits from Georgia (46 percent of Georgia’s exports). Tourism and remittances are other areas where Georgia is significantly tied to Russia and somewhat weaker to Ukraine. Before the pandemic, in 2019 Russia accounted for 24 percent of all tourism revenues, while Ukraine for 6 percent. Remittances from Russia accounted for 16.5 percent of total incoming transfers in 2021.
- Second, while the Georgian government chose to largely keep a neutral stance on the war (announcing at one point that they would not join or impose sanctions against Russia), the main financial and trade international sanctions were still in effect in Georgia due to international obligations and close business ties with the West. These factors were reinforced by strong support for Ukraine among the Georgian population, where the memory of the Russian invasion of Georgia in 2008 remains uppermost.
- In addition, Georgia is a net energy importer, and while the dependence on energy imports from Russia is not significant, the rising prices would have affected Georgia profoundly.
Original publication: This policy paper was originally published in the ISET Policy Institute Policy Briefs section by Yaroslava Babych, Lead Economist of ISET Policy Institute. To read the full policy paper, please visit the website of ISET-PI.
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.
The world is currently experiencing what can be labelled as a global energy crisis, with surging prices for oil, coal, and natural gas. For households in Sweden and abroad, 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 issues, and intensified as Russia invaded Ukraine at the end of February this year. In response, the Swedish government announced on March 14th this year that the tax rate on transport fuels would be temporarily reduced by 1.80 SEK per liter (€0.17) and that every car owner would receive a one-off lump-sum transfer of 1000 SEK in compensation (1500 SEK for car owners in rural areas). This reduction in transport fuel tax rates in Sweden is unprecedented. Since 1960, the nominal tax rate on gasoline has only been reduced three times – and then only by very small amounts, ranging from 0.04 to 0.22 SEK per liter. In this policy brief, we put the current gasoline price in Sweden into a historical context and answer two related questions: are Swedish households paying more today for gasoline than ever before? And should policymakers respond by reducing gasoline taxes?
The Price of Gasoline in Sweden
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 1924, Sweden introduced an energy tax on the price of 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). Before the announced tax cut this year, 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 changes in the oil price.
Figure 1. Gasoline pump price: 2000-2022
Figure 1 shows the monthly average real price of gasoline in Sweden from 2000 to March of 2022. The price has increased over the last 20 years and is today historically high. Going back even further, the price is higher today than at any point since 1960. Swedish households are thus paying more for one liter of gasoline than ever before.
Figure 2. Gasoline expenditure per 100 km
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 today in Sweden can drive 50 percent further on a liter of gasoline compared to new vehicles sold in 2000. Arguably, what consumers care about most is not the cost of one liter of gasoline per se but the cost of driving a certain distance – the utility we derive from a car is the distance we can travel. Accounting for the improvement over time in the fuel efficiency of new vehicles (Figure 2), 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 period from 2000-2008.
Second, any sensible discussion of the cost of personal transportation for households should also factor in changes in household income over time. The average real hourly wage has increased by close to 40 percent between 2000 and 2022. As such, the cost of driving 100 km, measured as a share of household income, has steadily gone down over time. Even more, this pattern is similar across the income distribution; for instance, the cost trajectory of the bottom decile group is similar to that of all employees. This is illustrated in Figure 3. In 1991, when the carbon tax was implemented, an average household had to spend around two-thirds of an hour’s wage to be able to drive a distance of 100 km. By 2020, that same household only had to spend one-third of an hour’s wage to drive the same distance. There is an increase in the cost of driving over the last two years but it is still cheaper today to drive a certain distance, in relation to income, compared to any year before 2012.
Taken all of this together, we have seen that over time, vehicles use fuel more efficiently on the expenditure side, and households earn higher wages on the income side. Based on this, we can conclude that the cost of travelling a certain distance by car is not historically high today. On the contrary, when measured as a share of income, it was 50 percent more expensive for most of the 21st century.
Figure 3. Cost of driving as a share of income
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 the household 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. And the change in the gasoline price at the pump has been unusually rapid over the last 12 months. From the beginning of 2021 until March of 2022, the pump price has risen by around 50 percent.
So, should policymakers respond by lowering gasoline taxes? The possibly 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 only 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, but in the US by around 80 percent. Furthermore, 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 and are even more vulnerable to rapid increases in the price of crude oil. Having high gasoline tax rates thus reduces – and not increases – the short run welfare impact on households. Hence, policymakers should resist the temptation to lower gasoline tax rates even during the current energy crisis. In the medium and long run, households would buy vehicles with higher fuel consumption and would be more exposed to price surges in the future, again compelling policymakers to adjust tax rates and creating a downward spiral. Instead, alternative measures should be considered to alleviate the effects of heavy price pressure on low-income households – for instance, revenue recycling of the carbon tax revenue and increased subsidies for public transport.
To reach environmental and climate goals, Sweden urgently needs to phase out the use of fossil fuels in the transport sector, which is 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 goes in the opposite direction. In Sweden, the Social Democrats – the governing party – have announced a tax cut on gasoline and diesel of 1.80 SEK per liter but the political parties in opposition have promised even larger tax cuts. Some proposals would even effectively abolish the entire energy and carbon tax on gasoline. Similar tax cuts have been announced for example in Belgium, France, the Netherlands, and Germany. Therefore, this time is indeed different – but in terms of the exceptional reactions from policymakers rather than in terms of the cost of gasoline that households face.
- IEA. (2021). “Fuel Consumption of Cars and Vans” Tracking Report, International Energy Agency, November 2021.
- SPBI. (2022). “Svenska Petroleum och Biodrivmedel Institutet: Data Set” SPBI. drivkraftsverige.se/statistik/priser/bensin/
- Statistics Sweden. (2022). “Average hourly wage statistics”. Available: http://www.statistikdatabasen.scb.se
- Trafikverket. (2022). “Vägtrafikens utsläpp 2021” Tech. rep., Swedish Transport Administration, February 7th 2022.
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.
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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- Rystad Energy. (2022b). “Energy Impact Report, Russia’s Invasion of Ukraine, public version”, March 21
- Stehn, S. J., Ball, S., Durre, A., Radde, S., Schnittker, C., Taddei, F. & Quadr, I. (2022). “The Impact of Gas Shortages on the European Economy”, Goldman Sachs, March
- Y. Daniel. (1992). The Prize: The Epic Quest for Oil, Money, and Power. New York: Simon and Schuster.
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.
The need for urgent climate action and energy transformation away from fossil fuels is widely acknowledged. Yet, current country plans for emission reductions do not reach the requirements to contain global warming under 2°C. What is worse, there is even reasonable doubt about the commitment to said plans given recent history and existing future investment plans into fossil fuel extraction and infrastructure development. This policy brief shortly summarizes the presentations and discussions at the SITE Development Day Conference, held on December 8, 2021, focusing on climate change policies and the challenge of a green energy transition in Eastern Europe.
Climate Policy in Russia
The first section of the conference was devoted to environmental policy in Russia. As Russia is one of the largest exporters of fossil fuel in the world, its policies carry particular importance in the context of global warming.
The head of climate and green energy at the Center for Strategic Research in Moscow, Irina Pominova, gave an account of Russia’s current situation and trends. Similar to all former Soviet Union countries, as seen in Figure 1, Russia had a sharp decrease in greenhouse gas emissions (hereinafter referred to as GHG emissions) during the early 90s due to the dramatic drop in production following the collapse of the Soviet Union. Since then, the level has stabilized, and today Russia contributes to about 5% of the total GHG emissions globally. The primary source of GHG emissions in Russia comes from the energy sector, mainly natural gas but also oil and coal. The abundance of fossil fuels has also hampered investments in renewable resources, constituting only about 3% of the energy balance, compared to the global average of 10%
Figure 1. Annual greenhouse gas emissions per capita
Pominova noted that it is a massive challenge for the country to reach global energy transformation targets since the energy sector accounts for over 20% of national GDP and 28% of the federal budget. Yet, on a positive note, the number of enacted climate policies has accelerated since Russia signed the Paris Agreement in 2019. One notable example is the federal law on the limitation of GHG emissions. This law will be enforced from the end of 2021 and will impose reporting requirements for the country’s largest emitters. The country’s current national climate target for 2030 is to decrease GHG emissions by 30% compared to the 1990 level. As shown in Figure 1, this would imply roughly a 10 percent reduction from today’s levels given the substantial drop in emissions in the 1990’s.
Natalya Volchkova, Policy Director at CEFIR in Moscow, discussed energy intensity and the vital role it fills in Russia’s environmental transition. Energy intensity measures an economy’s energy efficiency and is defined as units of energy per unit of GDP produced. Volchkova emphasized that to facilitate growth in an environmentally sustainable way it is key to invest in technology that improves energy efficiency. Several regulatory policy tools are in place to promote such improvements like bottom-line energy efficiency requirements, sectoral regulation, and bans on energy-inefficient technologies. Yet, more is needed, and a system for codification and certification of the most environmentally friendly technologies is among further reforms under consideration.
As a Senior Program Manager at SIDA, Jan Johansson provided insights on this issue from an international perspective. Johansson gave an overview of SIDA’s cooperation with Russia in supporting and promoting environmental and climate policies in the country. The main financial vehicle of Swedish support to Russia with respect to environmental policy has been a multilateral trust fund established in 2002 under the European Union (EU) Northern Dimension Environmental Partnership (NDEP). One of the primary objectives of the cooperation has been to improve the environment in the Baltic and Barents Seas Region of the Northern Dimension Area. Over 30 NDEP projects in Russia and Belarus have been approved for financing so far. Seventeen of those have been completed, and the vast majority have focused on improving the wastewater treatment sector.
Johansson also shed light on the differences that can exist between governments in their approach to environmental policy. For example, in the area of solid waste management, Russia prefers large-scale solutions such as landfills and ample sorting facilities. In Sweden and Western Europe, governments have a more holistic view founded on spreading awareness in the population, recycling, corporate responsibility, and sorting at the source.
Environmental Transition in Eastern Europe
In the second part of the conference environmental policies and energy transformation in several other countries in the region were discussed.
Norberto Pignatti, Associate Professor and Centre Director at ISET Policy Institute, talked about the potential for a sustainable energy sector and current environmental challenges in Georgia. The country is endowed with an abundance of rivers and sun exposure, making it a well-suited environment for establishing the production of renewable energy such as wind, solar, and hydro. As much as 95 % of domestic energy production comes from renewable sources. Yet, domestic energy production only accounts for 21% of the country’s total consumption, and 58% of imported energy comes from natural gas and 33% from coal. Furthermore, the capacity of renewable energy sources has declined over the last ten years, and particularly so for biofuel due to the mismanagement of forests. A notable obstacle Georgia faces in its environmental transition is attracting investors. Low transparency and inclusiveness from the government in discussions about environmental policy, along with inaccurate information from the media, has led to a low public willingness to pay for such projects. Apart from measures to overcome the challenges mentioned, the government is currently working on a plan to impose emission targets on specific sectors, invest in energy efficiency and infrastructure, and support the development of the renewable energy sector.
Like Georgia, Poland is a country where energy consumption is heavily reliant on imports and where coal, oil, and gas stand for most of the energy supply. On top of that, Poland faces significant challenges with air quality and smog and a carbon-intensive energy sector. On the positive end, Poland established a government-industry collaboration in September 2021, that recognizes offshore wind as the primary strategic direction of the energy transition in Poland. Pawel Wróbel, Founder and Managing Director of BalticWind.EU, explained that the impact of the partnership will be huge in terms of not only energy security but also job creation and smog mitigation. The plan implies the installation of 5.9 GW of offshore wind capacity by 2030 and 11GW by 2040. Wróbel also talked about the EU’s European Green Deal and its instrumental role in accelerating the energy transition in Poland. By combining EU-wide instruments with tailor-made approaches for each of the member states, the Deal targets a 55% reduction in GHG emissions by 2030 through decarbonization, energy efficiency, and expanding renewable energy generation. Michal Myck, Director of CenEA, highlighted the role of social acceptance in accelerating the much-needed energy transition in Poland. In particular, to build political support, there is a crucial need for designing carbon taxes in a way that ensures the protection of vulnerable households from high energy prices.
Adapting to the European Green Deal will also create challenges for countries outside of the EU, especially if a European Carbon Border Adjustment Mechanisms (CBAM) is put in place in 2026 as suggested. Two participants touched on this topic in the context of Belarus and Ukraine respectively. Yauheniya Shershunovic, researcher at BEROC, talked about her research on the economic implications of CBAM in Belarus. It is estimated that the introduction of CBAM can be equivalent to an additional import duty on Belarusian goods equal to 3.4-3.8% for inorganic chemicals and fertilizers, 6.7-13.7% for metals, and 6.5-6.6% for mineral products. Maxim Fedoseenko, Head of Strategic Projects at KSE, shared similar estimations for Ukraine, suggesting that the implementation of CBAM will lead to an annual loss of €396 million for Ukrainian businesses and a decrease in national GDP of 0.08% per year.
An example of Swedish support to strengthen environmental policies in Eastern Europe was presented by Bernardas Padegimas, Team Leader at the Environmental Policy and Strategy Team at the Stockholm Environment Institute. The BiH ESAP 2030+ project is supporting Bosnia and Herzegovina in preparing their environmental strategy. This task is made more challenging by the country’s unique political structure with two to some extent politically autonomous entities (and a district jointly administered by the two), and elites from the three different major ethnic groups having guaranteed a share of power. The project therefore aims to include a broad range of stakeholders in the process, organized into seven different working groups with 659 members on topics ranging from waste management to air quality, climate change and energy. The project also builds capacity in targeted government authorities, raises public awareness of environmental problems, and goes beyond just environmental objectives: mainstreaming gender equality, social equity and poverty reduction. The project is 80 percent finished and will produce a strategy and action plan for the different levels of governance in the country’s political system. There is also a hope that this process can serve as a model for consensus building around important but at times contentious policy issues more generally in the country.
Public Opinion and Energy Security
Finally, Elena Paltseva, Associate Professor at SITE, and Chloé le Coq, Professor at the University of Paris II Panthéon-Asses (CRED), shared two joint studies relating to the green transition in Europe.
Recent research shows that individual behavioral change has a vital role to play in the fight against climate change, both directly and indirectly through changes in societal attitudes and policies motivated by role models. A precondition for this to happen is a broad public recognition of anthropogenic climate change and its consequences for the environment. The first presentation by Paltseva and Le Coq focused on public perceptions about climate change in Europe (see this FREE policy brief for a detailed account). Using survey data the study explores variation in climate risk perceptions between Western Europe, the non-EU part of Eastern Europe, and Eastern European countries that are EU members. The results show that those living in non-EU Eastern European countries are on average less concerned about climate change. The regional difference can partly be explained by low salience and informativeness of environmental issues in the public discourse in these countries. To support this explanation, they study the impact of extreme weather events on opinions on climate change with the rationale that people who are more aware of climate change risks are less likely to adjust their opinion after experiencing an extreme weather event. They find that the effect of extreme weather events is higher in countries with less independent media and fewer climate-related legislative efforts, suggesting that the political salience of the environment and the credibility of public messages affects individuals’ perceptions of climate change risks.
The second presentation concerned energy security in the EU, and the impact of the environmental transition. It was argued that natural gas will play an important role in Europe’s green transition for two reasons. First, since the transition implies a higher reliance on intermittent renewable energy sources, there will be an increased need for use of gas-fired power plants to strengthen the supply reliability. Second, the electrification of the economy along with the phasing out of coal, oil, and nuclear generation plants will increase the energy demand. Today, about 20% of EU’s electricity comes from natural gas and 90% of that gas comes from outside EU, with 43% coming from Russia. To emphasize what issues can arise when the EU relies heavily on external suppliers, the presentation discussed a Risky External Energy Supply Index (Le Coq and Paltseva, 2009) that considers the short-term impact of energy supply disruptions. This index assesses not only the importance of the energy type used by a country but also access to different energy suppliers (risk diversification). The index illustrates that natural gas is riskier than oil or coal since natural gas importers in the EU depend to a greater extent on a single or few suppliers. Another crucial component of the security of gas supplies arises from the fact that 77% of EU’s net gas imports arrive through pipelines, which creates an additional risk of transit. Here, the introduction of new gas transit routes (from already existing suppliers) may increase diversification and decrease risks to the countries having direct access to the new route. At the same time, countries that share other pipelines with countries that now have direct access may lose bargaining power vis-à-vis the gas supplier in question, as demand through those pipelines could fall. Le Coq illustrated this point applying the Transit Risk Index developed in Le Coq and Paltseva (2012) to the introduction of the North Stream 1 pipeline. She concluded that the green transition and associated increase in demand for natural gas is likely to be associated with higher reliance on large gas producers, such as Russia, and resulting in energy security risks and imbalance in the EU. One way to counteract this effect is to exercise EU’s buyer power vis-a-vis Russia within the EU common energy policy. While long discussed, this policy has not been fully implemented so far.
This year’s SITE Development Day conference gave us an opportunity to highlight yet another key issue, not only for Eastern Europe, but for the whole world: global warming and energy transformation. Experts from across the region, and policymakers and scholars based in Sweden, offered their perspectives on the challenges that lie ahead, but also highlighted initiatives and investments hopefully leading the way towards a brighter future.
List of Participants
- Chloé Le Coq, Professor of Economics at the University of Paris II Panthéon-Assas (CRED). Paris, France. Research Fellow at SITE.
- Maxim Fedoseenko, Head of Strategic Projects at KSE Institute. Kyiv, Ukraine.
- Jan Johansson, Senior Program Manager, SIDA. Stockholm, Sweden.
- Michal Myck, Director of CenEA. Szczecin, Poland.
- Bernardas Padegimas, Team Leader: Environmental Policy and Strategy, Stockholm Environmental Institute. Stockholm, Sweden.
- Elena Paltseva, Associate Professor, SITE/SSE/NES. Stockholm, Sweden
- Norberto Pignatti, Associate Professor of Policy at ISET-PI, and Head of the Energy and Environmental Policy Institute at ISET-PI. Tbisili, Georgia.
- Irina Pominova, Head of Climatwe and Green Energy at the Center for Strategic Research. Moscow, Russia.
- Yauheniya Shershunovic, Researcher at BEROC, Minsk, Belarus. PhD Candidate at the Center for Development Research (ZEF). Uni Bonn.
- Natalya Volchkova, Policy Director at CEFIR, Assistant Professor at the New Economic School (NES). Moscow, Russia.
- Pawel Wróbel, Founder and Managing Director of BalticWind.EU. Poland.
- Julius Andersson, Researcher at SITE. Stockholm, Sweden.
- Anders Olofsgård, Associate Professor and Deputy Director at SITE. Stockholm, Sweden.
Due to the high volatility of natural gas market prices, it is almost impossible to adequately plan the purchases for the year ahead, so contract prices need to be regularly updated. This fact creates uncertainty for the contracting authorities, as well as room for unfair competition and corruption. We offer an indexation formula which uses the European gas prices as a benchmark for procurement prices and calculate the potential economic effect of this formula on the Ukrainian gas procurement market.
Problems with the Public Procurement of Natural Gas
Natural gas procurement poses a number of challenges for the contracting authorities (CAs), suppliers and controllers. Due to price volatility it is almost impossible to adequately plan the purchases for the year ahead, so prices need to be regularly adjusted. After the heating season starts, CAs find themselves in a weak position in price negotiations since they almost never have storage for accumulating stocks, and if the contract is cancelled the new procurement would take at least one month due to the existing public procurement regulations. The new version of the Law on Public Procurement, which was recently adopted by the Ukrainian parliament, addresses this problem by allowing CAs to have a new contract fast in case the previous contact was cancelled because of the supplier.
CAs often lack reliable data on market dynamics. There are cases when unreliable price references are provided by specialized agencies to support higher price claims of suppliers. As a result, CAs bear administrative responsibility if they do not have proper justification for changing contract prices when controlling agencies initiate an audit.
Natural gas suppliers may also find themselves in a situation of unfair competition. Since it is possible to win an open auction (i.e. by quoting a considerably lower than market price) and later raise the price to the market level with an additional contract, honest businesses might feel demotivated to participate in the procurement process. They cannot be sure if the contract price can be changed later because there is no proper legal mechanism to assess the need of such an adjustment.
Previous research shows that every third contract of natural gas purchase was amended with an additional contract at least once, usually raising the price for the customer (Shapoval, Memetova, 2017). Additional contracts are indeed used 1) as a tool for price overstatement by the supplier, 2) as a loophole for corruption, and 3) as a way to get a market price for a supplier who used dumping to win the auction (Gribanovsky, Memetova, 2017).
International Drivers of Gas Prices in Ukraine
Since 2016, the EU has been the only official exporter of natural gas to Ukraine. According to PwC, Ukraine imported 14.1 billion m3 in 2017, which is 44% of total gas consumption – the remaining 56% are extracted locally. In Ukraine, the prices for industrial consumers are not regulated, while the household prices are set by the government. Today, the average price on the unregulated gas market is in line with the prices in neighbouring countries – the Baltic states, Poland, Slovakia and Hungary (PricewaterhouseCoopers Advisory LLC, 2018).
European prices are formed on the large marketplaces. The two biggest hubs, Dutch TTF and British NBP, by far outweigh their competitors (ACER Market Monitoring Report, 2017). However, the third-biggest hub, German NCG, is the closest to the Ukrainian border, so its prices often become the benchmark for private traders. In some cases, NCG is the official benchmark for gas price – for instance, the purchase parity import price in Ukraine in 2017-2018 was based on this hub’s index.
In order to assess the impact of the European natural gas prices on procurement prices in Ukraine, we used the Month+1 futures hub prices from TTF, NCG and Austrian VTP CEGH. Procurement prices were extracted from the analytical module of ProZorro (the Ukrainian e-procurement system which CAs are obliged to use at all levels). We excluded irrelevant procurements and selected the contracts which had information on the volume procured. We calculated the average daily prices weighted by volume. Our dataset covers the time period from January 1, 2017 to December 31, 2018.
Figure 1: Natural gas prices at ProZorro and European hubs
As one can see in Figure 1, hubs prices are highly correlated, so they cannot be used as independent variables within a single model. Thus, we decided to take the NCG Month+1 price as a benchmark for explaining the relation between internal procurement prices and international market prices.
NCG Impact on Procurement Prices in ProZorro
In the period of low business activity on natural gas markets, especially in summer, few contracts are awarded. One might have noticed from Figure 1 that this leads to higher variance in daily prices caused by random factors. Therefore, in our model we decided to use the weighted average of weekly prices instead.
Figure 2: Weekly gas price fluctuations in ProZorro and NCG
Our econometric estimation shows that the NCG Month+1 price influences procurement prices with a lag of 7 weeks. In other words, the price at the German hub becomes relevant for the Ukrainian procurement market after almost 2 months on average.
Figure 3: Correlations between procurement prices and NCG Month+1 with different lags
According to the model, the weighted average gas price in ProZorro is more dependent on the NCG Month+1 gas price than on the reservation price in ProZorro. Thus, a UAH 1 increase in the reservation price adds UAH 0.41 to the final price, while each additional hryvnia of the NCG price leads raises the final price by UAH 0.63 in 7 weeks if the price growth trend is not taken into account.
Potential Cost-Saving Using the Price Indexation Formula
The Price Indexation Formula
As European gas prices strongly influence prices on the internal Ukrainian market, it is obvious that they should be included into the indexation formula, as well as exchange rate fluctuations. After consultations with stakeholders, the Ministry of Economic Development and Trade of Ukraine (MEDT) decided to adjust the initial formula proposed by the KSE and included price fluctuations on the Ukrainian Energy Exchange (UEEx) with a small weight into the formula in order to stimulate UEEx development.
The final formula was officially published in December 2018. This formula is not compulsory for any contract authorities, though it is recommended for use by the smaller public entities who do not have the in-house analytical capacity to make a realistic price assessment during negotiations with the suppliers.
- CP – new price in UAH for 1000 m3 of natural gas (including value-added tax, VAT)
- PCP – current price in UAH for 1000 m3 of natural gas (including VAT) before adjustment
- K(cur) – average National Bank of Ukraine (NBU) UAH/EUR exchange rate for 5 days before the price change
- K(base) – average NBU UAH/EUR exchange rate on the day of the previous price adjustment (contract signed)
- NCG(avg) – average of daily NCG Month+1 index during 20 previous trading days before the day of price amendment, EUR per MW-hour
- NCG(base) – NCG Month+1 index on the day of the previous price amendment (contract signed), EUR per MW-hour
- VAT – rate of value-added tax, which is currently 20% in Ukraine
- CV – heating value of natural gas in MW-hour/1000 m3 on the date of the price adjustment
- UEEx(avg) – weighted monthly average natural gas price of UEEx (including VAT) on the day of price amendment
- UEEx(base) – weighted monthly average natural gas price on the UEEx (including VAT) on the day of the previous price amendment (contract was signed)
Thus, the formula includes current gas price, exchange rate changes, changes in NCG index and UEEx index.
Estimation of Potential Cost-Saving for Contract Authorities
The simplest yet time-efficient way to empirically verify the hypothesis of potential cost-saving after the introduction of the price indexation formula in the gas market is a retrospective analysis of the contracts which had already been signed.
The basic principle of estimation is comparing actual prices with the potential prices calculated based on the price indexation formula. For this, we collected a dataset of natural gas procurement contracts covering the time period from August 2017 to the end of August 2018. This period includes both short-term contracts signed for the heating season or its part (usually signed in August-September, sometimes in January-February) and middle-term contracts which are active for at least one year (usually signed in December-March). We took into account all the additional contracts to these contracts signed before January 1, 2019.
Supply schedules and prices of additional contracts are not readily available in a machine-readable format, so we kept only contracts with the total value higher than UAH 1 million. These are 27.5% of all contracts but they cover 79.3% of the total value of natural gas procurement in Ukraine. The final dataset contains prices of additional contracts and monthly supply schedules.
Our earlier analysis of all the contracts on the shorter time scale showed no correlation between prices and volumes in gas procurement contracts (Shapoval, Memetova et al., 2017), therefore our results can be extrapolated to all the gas contracts.
The biggest gap between actual and indexation prices would be in November 2017, averaging UAH 623. However, until the end of the year the gap reduced threefold to UAH 170.
Figure 4: Monthly increase of gas procurement prices
We combined the supply schedules with the prices found in the additional contracts in order to estimate potential savings. Obviously, the highest savings were observed during the heating season. However, in September they were negative (see Figure 6). Thus, while the market prices of natural gas started rising in August, actual procurement prices lagged behind until the end of September-October.
Figure 5: Monthly cost savings in case of applying price indexation formula
In total, for contracts of over UAH 1 million, potential cost savings from applying the price indexation formula would have been equal to UAH 120.25 million. If these estimations are extrapolated to all the contracts, this figure would reach UAH151.6 million. This is a rather modest sum in relative terms – only 2.7% of the total contract value. However, using the formula is expected to assist smaller CAs who often lack the knowledge of market dynamics to negotiate the optimal price more effectively and limit their dependence on the suppliers’ estimates.
Besides, the parties concluded the contracts without taking into account the opportunity of using the indexation formula. Therefore, actual cost savings might be lower, first of all because the suppliers’ auction strategy would be different. In particular, the dumping strategy with subsequent price increase through additional contracts would become useless. If the formula is used, a lower starting price would mean a lower increase in absolute terms (UAH per 1000 m3), because the formula calculates the change in relative terms (in per cent). For example, if the market price grows by 15% during the indexation period, the starting price can also be raised by only 15%.
The application of the price indexation formula for natural gas procurement may have a positive impact on the public procurement market. We recommend taking into account the prices of the European hubs adjusted by exchange rate fluctuations.
Had the price indexation formula been used for additional contracts in gas procurement in 2017-2018, the average price would have declined by UAH 623, potentially allowing CAs to save UAH 151.6 million.
Formula pricing would raise the negotiation power of customers (CAs) before the start of the heating season. This is especially true for the smaller ones which are not able to professionalize procurement processes. Natural gas price indexation within clearly defined boundaries will create more favourable conditions for fair competition by eliminating the stimuli for dumping at the auction stage.
- ACER Market Monitoring Report, 2017 “Gas Wholesale Markets Volume”.
- Gribanovsky Olexiy, Memetova Inna, 2017. “Additional contracts as a result of price dumping” (in Ukrainian).
- Order of CMU 187 of March, 22 2017, http://zakon.rada.gov.ua/laws/show/867-2018-%D0%BF#n127 (in Ukrainian).
- PricewaterhouseCoopers Advisory LLC, 2018. “Ukrainian gas market: Discovering investment potential and opportunities”.
- Shapoval Natalia, Memetova Inna, 2017. “Additional contacts in Ukraine: causes and methods of prevention” (in Ukrainian).
- Shapoval Natalia, Memetova Inna, Gribanovsky Olexiy, Tchmil Olexandra, 2017. “Three Sources of Losses in Natural Gas Public Procurement” (in Ukrainian).
- CEP, 2019. Source code of the project [github repository] https://github.com/cep-kse/natural_gas_formula.
- EUStream, Energy content at Budince. [web page] https://tis.eustream.sk/TisWeb/#/?nav=bd.gcv.
- PowerNext, 2017. Futures market data. [web page]. Retrieved from https://www.powernext.com/futures-market-data.
- ProZorro, 2014-2020. Ukrainian public procurement data. [bi system] http://bi.prozorro.org.
It has long been recognized that consumers fail to choose the cheapest and most efficient energy-consuming investments due to a range of market and non-market failures. This has become known as the ‘Energy Efficiency Gap’. However, there is currently a growing interest in terms of understanding on how consumers make decisions that involve an energy consumption component, and whether the efficiency of their decisions can be improved by changing the market incentives and governmental regulation. Meeting this interest, the most recent SITE Energy Talk was devoted to Demand Side Management. SITE invited Eleanor Denny, Associate Professor of Economics at Trinity College Dublin, and Natalya Volchkova, Assistant Professor at the New Economic School (NES) in Moscwo and Policy Director at the Center for Economic and Financial Research (CEFIR) to discuss the Demand Side Management process. The aim of this brief is to present the principles of Demand Side Management and discuss a few implemented programs in Europe, based on the discussions during this SITE Energy Talk.
For the last two decades, climate change policies have mostly been focused on the energy supply side, constantly encouraging new investments in renewables. But reducing energy demand may be as effective. Indeed, Denny and O’Malley (2010) found that investing 100MW in wind power is equivalent, in terms of emissions, to a decrease in demand of 50MW. Hence, there is a clear benefit of promoting energy saving. This has been the central point of different Demand Side Management (DSM) programs that may diversely focus on building management systems, demand response programs, dynamic pricing, energy storage systems, interruptible load programs and temporary use of renewable energy. The goal of these programs is to lower energy demand or, at least, smoothen the electricity demand over the day (i.e. remove peak-hour segments of demand to off-peak hours) as illustrated in Figure 1.
Figure 1 – Smoothing electricity demand during the day
A behavioral framework
DSM encompasses initiatives, technologies and installations that encourage energy users to optimize their consumption. However, the task does not seem easy, given the well-documented energy efficiency gap problem (e.g. Allcott & Greenstone, 2012 or Frederiks et al., 2015): consumers do not always choose the most energy efficient investments, despite potential monetary saving. One reason why might be that energy savings per se are not enough to trigger investment in energy efficient solutions or products. As Denny mentioned in her presentation, consumers will invest when the total private benefits are higher than the costs of investment. This trade-off can be summarized by the following equation:
This equation illustrates that any DSM design should take into account both non-monetary benefits and consumers’ time preferences. The non-monetary benefits, such as improved comfort, construction and installation time, but also warm glow (i.e. positive feeling of doing something good) or social comparison, may play a major role. Moreover, the consumers’ time preferences (reflected here by the discount rate ) are also crucial in the adoption of energy efficient products. In particular, if consumers have present biased preferences, they would rather choose a product with a lower cost today and greater future cost than the reverse (i.e. higher cost today with lower future cost). Since energy-efficient products often require higher upfront investment, consumers that are impatient for immediate gains, may never choose energy efficient products.
Ultimately, it is an empirical (and context specific) question when and why DSM programs can reduce the energy efficiency gap. We describe below some DSM programs that have been implemented and discuss their impact.
Smart meters, a powerful DSM tool
A common DSM program is the installation of smart meters, which measure consumption and can automatically regulate it. The adoption of smart meters allows real-time consumption measures, unlike traditional meters that only permitted load profiling (i.e. periodic information of the customer’s electricity use).
Figure 2 – Energy Intensity in Europe
As illustrated in Figure 2, many European countries have implemented smart meter deployment programs. Interestingly, most of those countries have a relatively high level of energy efficiency (proxied by the energy intensity indicator of final energy consumption). On the contrary, in the Balkans and non-EU Eastern Europe countries, which fare poorly on the energy intensity performance scale, no smart meter rollout programs seem to be implemented.
Following the European Commission (EC) directive of 2009 (Directive 2009/72/EC), twenty-two EU members will have smart meter deployment programs for electricity and gas by 2020 (see Figure 2). These programs are targeting end-users of energy, e.g. households that represent 29% of the current EU-28’s energy consumption, industries (36.9%) and services (29.8%) (EEA). With this rollout plan, a reduction of 9% in households’ annual energy consumption is expected.
The situation across the member states is however very different. Spain was one of the first EU countries to implement meters in 1988 for industries with demand over 5MW. All the meters will be changed at the end of 2018. 27 million euros for a 30-year investment in smart meter installations is forecasted (EC, 2013). Sweden started to implement smart meter rollout in 2003 and 5.2 million monthly-reading meters were installed by 2009. Vattenfall, one of the major utilities in Sweden, assessed their savings up to 12 euros per installed smart meter (Söderbom, 2012). Similarly in the United Kingdom, the Smart Metering Implementation Programme (SMIP) is estimated to bring an overall £7.2 billion (8.2 billion euros) net benefit over 20 years, mainly from energy saving (OFGEM, 2010). In general, smart metering has been effective, but its effectiveness may diminish over time (Carroll et al, 2014).
From smart-meter to real-time pricing
The idea of real-time pricing for electricity consumers is not new. Borenstein and Holland (2005) and Joskow and Tirole (2006) argue that this price scheme would lead to a more efficient allocation, with lower deadweight loss than under invariant pricing.
By providing detailed information about real-time consumption, smart meters enable energy producers to adopt dynamic pricing strategies. The increasing adoption of smart meters across Europe will likely increase the share of real-time-pricing consumers, as well as the efficiency gains. With the digitalization of the economy, it is likely that smart metering will grow. Indeed, Erdinc (2014) calculates that the economic impact of smart homes on in-home appliances could result in a 33% energy-bill reduction, due to differences in shift potential of appliances.
In 2004, the UK adopted a time-of-use programme called Economy 10, which provides lower tariffs during 10 hours of off-peak periods – split between night, afternoon and evening – for electrically charged and thermal storage heaters. The smart time-of-use tariffs involving daily variation in prices were only introduced in 2017.
Likewise, France’s main electricity provider EDF, implemented Tempo tariff for 350,000 residential customers and more than 100,000 small business customers. Based on a colour system to indicate whether or not the hour is a peak period, customers can automatically or manually monitor their consumption by controlling connection and disconnection of separate water and space-heating circuits. With this program, users reduced their electricity bills by 10% on average.
In Russia, the “consumptions threshold” program discussed by Natalya Volchkova, gave different prices for different consumption thresholds. But it seems that the consumers’ behaviour did not change. This might be due to the thresholds being too low, and an adjusted program should be launched in 2019.
Joskow and Tirole (2007), argue that an optimal electricity demand response program should include some rationing of price-insensitive consumers. Indeed, voluntary interruptible load programs have been launched, mainly targeting energy intensive industries that are consuming energy on a 24/7 basis. These programs consist of rewarding users financially to voluntarily be on standby. For instance, interruptible programmes in Italy apply a lump-sum compensation of 150,000 euros/MWh/year for 10 interruptions and 3000 euros/MW for each additional interruption (Torriti et al., 2010).
Nudging with energy labelling
Energy labelling has been also part of DSM. Since the EC Directives on Ecodesign and Energy Labelling (Directives 2009/125/EC and 2010/30/EU), energy-consuming products should be labelled according to their level of energy efficiency. For Ireland, Eleanor Denny has tested how labelling electrical in-home appliances may affect consumers’ decisions, like purchasing electrical appliances or buying a house. First, Denny and co-authors have nudged buyers of appliances, providing different information regarding future energy bills saving. They find that highly educated people, middle income and landlords are more likely to be concerned with energy-efficiency rates, rather than high-income people.
In another randomized control trial, Denny and co-authors manipulate information on the energy efficiency label for a housing purchase. In Ireland, landlords are charged for energy bills even when they rent out their property. The preliminary findings are that landlords informed about the annual energy cost of their houses are willing to pay 2,608 euros for a one step improvement in the letter rating – the EU label rating for buildings ranges from A to G – compared to the landlords that do not receive the information (see CONSEED project).
Similar to the European Directive, the 2009 Russian Energy efficiency law includes compulsory energy efficiency labels for some goods and improvements of the building standards (EBRD, 2011). Volchkova and co-authors run a randomized controlled experiment on the monetary incentives to buy energy efficient products. In 2016, people in the Moscow region received a voucher with randomly assigned discounts (-30%, -50% or -70%- for the purchase of LED bulbs. Vouchers were used very little, irrespective of the income. It seems that consumption habits and not so much monetary rewards were the main driver of LED bulb purchase.
How can DSM be improved?
Any demand response program requires some demand elasticity. For example, smart meters and dynamic pricing only improve electricity consumption efficiency if demand is price elastic. As Jessoe and Rapson (2014) show, one should provide detailed information (e.g. insights on non-price attributes, real-time feedback on in-home displays) to try to increase demand elasticity. Hence it seems that the low adoption of energy efficient goods is partly due to a lack of information or biased information received by the consumers. First, it is difficult for many to translate energy savings in kWh in monetary terms. Second, many consumers focus on the short-term purchase cost and discount heavily the long run energy saving. These information inefficiencies can, in principle, be diminished by private actors and/or governmental regulation. Denny mentioned the possibility of displaying monetary benefits on labels in consumers’ decision-making in order to improve energy cost salience. For instance, in the US or Japan, the usage cost information is also displayed in monetary terms. Moreover, lifetime usage cost (i.e. cost of ownership) should also be given to the customers since it has been shown that displaying lifetime energy consumption information has significantly higher effect than presenting annual information (Hutton & Wilkie 1980; Kaenzig 2010).
Summing up, DSM programs, including those with a behavioral framework, are an important tool for regulators, households and industries helping to meet emissions reduction targets, significantly decrease demand for energy and use energy more efficiently.
- Allcott, Hunt ; Greenstone, Michael. 2012. “Is There an Energy Efficiency Gap?”, Journal of Economic Perspectives, 26 (1): 3-28.
- Borenstein, Severin; Holland, Stephen. 2005. “On The Efficiency Of Competitive Electricity Markets With Time-Invariant Retail Prices”, Rand Journal of Economics, 36(3), 469-493.
- Carroll, James; Lyons, Seán; Denny, Eleanor. 2014. “Reducing household electricity demand through smart metering: The role of improved information about energy saving,” Energy Economics, 45(C), 234-243.
- Denny, Eleanor; O’Malley, Mark. 2010. “Base-load cycling on a system with significant wind penetration”, IEEE Transactions on Power Systems 2.25, 1088-1097.
- Erdinc, Ozan. 2014. “Economic impacts of small-scale own generating and storage units, and electric vehicles under different demand response strategies for smart households”, Applied Energy, 126(C), 142-150.
- European Bank for Reconstruction and Development. “The low carbon transition”. Chapter 3 Effective policies to induce mitigation (2011).
- European Commission. Electricity Directive 2009/92. Annex I.
- European Commission. Ecodesign and Energy Labelling Framework directives 2009/125/EC and 2010/30/EU.
- European Commission. “From Smart Meters to Smart Consumers”, Promoting best practices in innovative smart metering services to the European regions (2013).
- European Commission. “Benchmarking smart metering deployment in the EU-27 with a focus on electricity” (2014).
- European Environment Agency. Data on Final energy consumption of electricity by sector and Energy intensity.
- Frederiks, Elisha R.; Stenner, Karen; Hobman, Elizabeth V. 2015. “Household energy use: Applying behavioural economics to understand consumer decision-making and behaviour”, Renewable and Sustainable Energy Reviews, 41(C), 1385-1394.
- Hutton, Bruce R.; Wilkie, William L. 1980. “Life Cycle Cost: A New Form of Consumer Information.” Journal of Consumer Research, 6(4), 349-60.
- Jessoe, Katrina; Rapson, David. 2014. “Knowledge is (less) power: experimental evidence from residential energy use”, American Economic Review, 104(4), 1417-1438.
- Joskow, Paul; Tirole, Jean. 2006. “Retail Electricity Competition“, Rand Journal of Economics, 37(4), 799-815.
- Joskow, Paul; Tirole, Jean. 2007. “Reliability and Competitive Electricity Markets”, Rand Journal of Economics, 38(1), 60-84.
- Kaenzig, Josef; Wüstenhagen, Rolf. 2010. “The Effect of Life Cycle Cost Information on Consumer Investment Decisions Regarding Eco‐Innovation”, Journal of Industrial Ecology, 14(1), 121-136.
- OFGEM. “Smart Metering Implementation Programme” (2010).
- Söderbom, J. “Smart Meter roll out experiences”, Vattenfall (2012).
- Torriti, Jacopo; Hassan, Mohamed G.; Leach, Matthew. 2010. “Demand response experience in Europe: Policies, programmes and implementation”, Energy, 35(4), 1575-1583.
Eleanor Denny and co-authors’ European research projects:
- CONSEED (Consumer Energy Efficiency Decision making) https://www.conseedproject.eu/
- NEEPD (Nudging Energy efficient Purchasing Decisions) https://www.neepd.com/
This policy brief summarizes the discussion at the 8th annual SITE Energy Day conference, devoted to market adaptations and policies necessary to address the green transition. Recent energy trends with ever more green energy-mixes will have consequences for the functioning of related markets as well as implications for appropriate policy responses. New financial solutions, technological developments, international cooperation, and national policy initiatives in both developing and developed countries are examples of adaptations to this transition process. To discuss these issues, the conference brought together a group of distinguished experts from the energy industry, policy community and academia.
In December 2014, world leaders have gathered in Peru (Lima) for the 20th annual meeting of the United Nations Framework Convention on Climate Change. This convention has as an objective to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system” (see UNFCCC’s webpage). Even though the agreement to reduce emissions to a sustainable level may take years to be negotiated, at least 195 countries have ratified the UFCCC convention. The willingness to reduce environmentally harmful emissions has led to many countries changing their energy profile to include more green energy, a process that is often referred to as “green transition”.
It may be worth mentioning that the label “green transition” consists of two conceptual components. “Green” refers to the ability to generate environmentally friendly energy, which has become a key challenge for our society. Indeed, a majority of people now recognize the pressing need to cut pollution in the face of climate change and environmental degradation. The wording “transition” acknowledges that a shift toward a greener energy mix seems unavoidable, but this shift may not occur immediately or uniformly around the globe. The required time for change is long and the shift itself may not be smooth. To put it differently, the green transition has had and will continue to have wide-ranging consequences for businesses, governments, and the international community.
As a result, there is a need to carefully address the potential implications for the existing energy and related markets and market players, and for government policies, as well as new markets and new policies triggered by the green transition. These topics were the focus of the 8th SITE Energy Day, a half-day conference held at the Stockholm School of Economics on December 2, 2014.
Green Transition and the Energy Markets
The first panel focused on how energy markets have responded to green transition and how they may react in the future. Speakers from electricity companies, regulatory bodies and think tanks discussed how the green transition may affect the use of traditional financial instruments by energy companies; the choice of economically viable technology for producing green energy; and the way markets could be integrated to increase the efficiency of green energy.
As green transition almost always introduces more intermittent production, it is likely that market uncertainty will increase. This is one of the reasons why traditional financial instruments may not be fully adequate. The first speaker Laurent Cheval, Head of Nordic and Fuel Origination in the business division Asset Optimization & Trading at Vattenfall discussed this issue extensively. Energy companies face substantial financial risks since both prices and quantities may be highly volatile. To mitigate these risks, market participants may use an array of financial products. In mature energy markets, the products are fairly standardized. However, more complex and tailor-made financial products are required to face the ongoing changes in the sector. For example, the increased share of renewable energy combined with more interconnected markets create specific market risks. To hedge against risks associated with weather changes, future fuel costs, interest rates and so on, more and more energy providers trade customized derivatives “over-the-counter” (OTC) rather than through a centrally-cleared exchange. Another example is the development of decentralized power production and the rise of the “Prosumer” who simultaneously produces and consumes power. So far, the relevant regulation is underdeveloped and there is an additional demand for innovative financial solutions. Large energy companies such as Vattenfall are for instance offering a range of financial hedging solutions combined with actual physical handling and delivery of energy products.
Green transition should in the long run lead to a domination of environment friendly energy. However it is important that only economically viable technologies subsist. It is therefore necessary to assess the cost of producing green energy. Lars Andersson, Head of Wind Power Unit at the Swedish Energy Agency, reported on an extensive study done by the Agency on this issue. Over the last five years, the production cost of wind power has fallen consistently and capacity usage has increased. This dramatic change in the wind power industry likely implies that the existing subsidies for building wind power plants gradually will be phased out. It is unclear how the industry will react to these cuts in subsidies. Furthermore, according to Andersson, wind production faces at least two challenges. Without developing the capabilities for energy storage, electricity markets will face more energy imbalances as the share of wind power increases. Additionally, the support from the local communities is needed to ensure an expansion of wind power. Addressing these issues requires the development of new regulation and defining a common goal which may promote cooperation between stakeholders.
Ultimately the green transition will end when and if the green energies are largely adopted around the globe. One way to accelerate this green transition may be to coordinate action and development of governmental policies. Martin Ådahl, Chefsekonom at Centerpartiet, and Daniel Engström, Programchef Miljö och Klimat at Fores, presented the current state of the international climate policy and discussed the benefits of linking carbon emission rights markets. Because of conflicting interests, the likelihood of reaching an agreement within the current United Nations climate negotiations is rather small.
However, Ådahl and Engström suggested that the focus should instead be on reaching agreements between big polluter countries that contribute the lion’s share of global emissions. Indeed, regional emission trading schemes already exist in the EU, the US and China, the three regions which together account for over 50 percent of global emissions. One potential shortcoming of this suggestion is that it may not be enough to stabilize greenhouse gas concentrations in the atmosphere. Thereby, Ådahl and Engström discussed the possibility to link current cap-and-trade markets, as a first step toward an international system with a more formal global agreement. Linking cap-and-trade markets has many benefits, especially in the form of efficiency gains. However, emission caps vary across countries and regions because of different political goals or priorities. When markets are linked, difference in abatement costs (or allowance prices) would lead to a flow of allowances and emissions from countries/regions with low abatement cost to countries with higher ones. Thereby prices would be equalized, benefiting entities with cheaper allowances. To avoid opportunistic behavior, countries would first have to agree ex ante on an exchange rate between different countries’ emission rights. Second, a clear regulatory framework is required. Both Ådahl and Engström emphasized the need of an international organization devoted to climate economics. Such an institutional body could not only regulate the links between cap-and-trade markets, but also provide concrete solutions and technical models to improve on the market design.
Environmental Policies: International Experience
The second panel focused on how governments may promote green transition. Anna Pegels, Senior Researcher at the German Development Institute (DIE), reviewed green policy initiatives in developing countries. Pegels argued based on evidence from e.g. India and South Africa that it is possible to combine substantial growth with green energy. This is good news since emerging countries are among the highest polluters. However, to change a country’s energy profile, governments need to intervene and develop new industrial policies.
Governments can set long-term goals, which are supported by short- and mid-term targets. However, given the large profits that are at stake, officials may likely be subject to the risk of capture and corruption. To limit such risks, Pegel emphasized the need to introduce competition in the energy sector as a whole. Subsidized feed-in tariffs for renewable energy for example should be only a first step, to reach a certain scale of production. But the technology is mature enough that producers should be able to bear some additional risk in their current activity. This should increase the scope for competition. Finally, it is essential that governments continuously engage in policy revision cycles and learn from other countries’ experiences.
Benjamin Sovacool, Professor of Business and Social Sciences at Aarhus University and Director of the Danish Centre for Energy Technologies, talked about the process of low carbon transition in the Nordic region. In spite of large investments into renewable energy, fossil fuels still dominate the consumption in the Nordic countries and considerable measures need to be taken in the decades ahead to make the transition to a greener energy mix. Sovacool highlighted four areas which could help reduce the carbon footprint of the Nordic countries: renewable energy, increased energy efficiency of buildings, transportation, and carbon capture and storage (CCS). In order to be successful, the green transition has to bring about a systemic change engaging actors across the economy, particularly including end-users. There should also be a focus on additional technological progress. Finally, Sovacool noted that a rapid emission reduction such as the one planned in the Nordic countries is unlikely to be followed on a global scale in the near future due to a lack of political feasibility.
The green transition is expected to have a profound impact on the functioning and structure of energy markets as well as the policies that facilitates this transition.
There is an ongoing process of decentralization in the energy sector, with the rise of “prosumer” market places that alter market dynamics. Moreover, market uncertainty is increasing due to more intermittent production (due to renewables) and a stronger interconnectedness between energy markets. It is likely that energy imbalances will be a major concern and that more and more energy trade will take place on real time markets (as opposed to e.g. on the day-ahead market). As markets’ linking becomes stronger, the interdependence between markets in terms of energy type and geographical location will be intensified. The need for coordination and international cooperation will be even more pressing. The uncertainty regarding the development of international cooperation, but also regarding national policy changes, may however disrupt energy markets. Measures such as withdrawing existing subsidies must be handled in a gradual and strategic manner so as not to discourage investment. A key issue for governments is to have a credible green policy in the long-term. Such credibility will also depend on the level of involvement of different actors in the green transition, including the necessity to have a multilevel engagement of the end-users.
- Energimyndigheten, (2014), Produktionskostnads-bedömning för Vindkraft i Sverige, ER 2014:16
- Pegels, A. (Ed.). (2014), Green industrial policy in emerging countries, Vol. 34, Routledge
- Rutqvist, J., Engström, A.and Ådahl, M., A Bretton Woods for the Climate. Fores, 2010
- SITE 8th Energy Day, http://www.hhs.se/en/about-us/calendar/site-external-events/2014/site-energy-day/
- UNFCCC, (n.d). First steps to a safer future: Introducing The United Nations Framework Convention on Climate Change, http://unfccc.int/essential_background/convention/items/6036.php [8 December 2014]