Global effort to reduce greenhouse gas emissions is continuously growing stronger. Realisation of a direct correlation between the quality of life and environmental aspects of electricity generation has been at the heart of the ongoing energy sector transformation.
Global effort to reduce greenhouse gas emissions is continuously growing stronger. Realisation of the direct correlation of quality of life to the environmental aspects of the energy sector has been in the heart of the new energy paradigm. In this light, ensuring full awareness of current and potential emissions with regard to market circumstances and policy implications is crucial in acquiring a better overview on the current issues and future development of the energy system. Research presented offers a methodology for calculating direct CO2 emissions from electricity generation, as well as an insight to current issues and future prospects of the South East Europe electricity market. Observing various scenarios, the region’s future performance is evaluated with special consideration given to the potential impact of carbon prices.
Direct carbon emissions of electricity production: A case study for South East Europe
Research presented analyses a some of the issues regarding CO2 emissions from the electricity generation sector. First off, it establishes a mathematical framework for the optimisation process and the market analysis in order to be able to: (1) determine direct CO2 emissions of electricity production and (2) forecast the variation of these emissions caused by changing market or regulatory circumstances. Second, through a case study market analysis, it applies the established framework in order to: (1) reveal the influence of selected market factors on CO2 emissions and (2) analyse the influence of carbon prices on the electricity sector (giving special consideration to the change in electricity prices, CO2 emissions and unit productions).
The case study analysis is conducted for two different years, 2017 and 2021, to best represent the current situation and the business as usual (BAU) scenarios for the first year of the potential Phase IV of the EU Emission trading scheme.
The energy sector is one of the largest emitters of anthropogenic carbon emissions as fossil fuels are used in producing over two thirds of the world’s electricity. According to a recent report by IEA, coal, natural gas and oil hold 39.3%, 22.9% and 4.1% shares in overall electricity generation. Due to the awareness of the negative environmental impact of fossil fuel combustion, the energy sector has been experiencing fundamental changes dramatically changing its landscape. Success of an energy sector is not determined strictly by the profit it brings, but by measuring the affordability, reliability and sustainability of the energy it provides.
As a result of increased concern regarding environmental issues, there have been a number of attempts to quantify and reduce the amount of GHG emissions into the atmosphere. Well-known organisations such as the Intergovernmental Panel on Climate Change (IPCC) and UNFCCC developed GHG emission calculation methodologies as a tool to support the combat against climate change. Additionally, there are some research papers analysing emissions.
Considering the context of carbon emissions, EU is striving to lead the war on global warming by initiating a number of policy changes facilitating the transformation of the energy sector to a low-carbon economy. Emission trading scheme (ETS) was envisioned as one of the key tools in the combat against harmful GHG emissions. ETS is a market-based scheme allowing participants to trade emission permits in order to account for their emissions. The number of allowances is reduced year by year and the price of an allowance was forecasted to increase. This, in turn, would raise costs for polluters and effectively encourage them to either reduce their output or opt for environmentally more sustainable options. However, the implementation of ETS did not yield expected benefits. Apart from the peak recorded in July 2008, when the price of an emission unit allowance (EUA) rose to 29.2 €/tCO2, carbon prices remained too low to influence the facilitation of a shift towards renewable energy solutions in a more concrete manner. For example, in 2017, according to the European energy Exchange (EEX), the average price of a permit equalled just below 5.6 €/tCO2, far too low to encourage a more noticeable market shift.
While looking at the situation in the USA, one can easily see that the United States Environmental Protection Agency (EPA) carefully monitors all GHG emitters through its Greenhouse Gas Reporting Program (GHGRP). The data is frequently refreshed and available online through a comprehensive list containing over 7,000 emitting points divided into direct emitters and suppliers. However, not each country or energy sector is as transparent. For instance, obtaining such data for counties based in South East Europe (SEE) would be quite an arduous task. There is no available public data regarding CO2 emissions of the electricity sectors of the region and no reporting programme. In fact, a number of countries does not even measure emissions nor are they a part of the ETS.
South East Europe (SEE) is slowly adapting to the requirements of this new energy paradigm, but faces significant drawbacks as a journey in achieving an affordable, safe and sustainable supply of energy holds a number of challenges. Most notable difficulties are related to policy and investment issues, but also to the plain fact that their electricity sectors are historically tied to traditional sources of primary energy. As the majority of European countries transition towards sustainable energy futures, a number of SEE countries are failing to adapt to new circumstances and still value their energy policies on a set of limited input factors. Region’s electricity production sector is dominated by hydro and lignite sources. It is the old lignite-based generation fleet of power plants that causes the emission of a considerable amount of CO2 into the atmosphere.
Overall CO2 emissions in South East Europe in 2017
CO2 emissions in SEE, 2017
Overall emissions in 2017 are estimated to amount to 100 MtCO2. Out of the eleven countries analysed, Bulgaria, Romania and Serbia emit highest quantities of CO2, each emitting over 20 MtCO2. On the other hand, looking at specific emissions, Kosovo is worst placed emitting over 0.9 tCO2 per MWh. This is not a surprise considering their electricity production is based on an old thermal unit of low efficiency and fired by local lignite.
Specific emissions in SEE, 2017
Specific CO2 emissions tCO2 per MWh of demand in South East Europe in 2017
Future projection & case studies
After analysing the current situation regarding CO2 emissions, the analysis focuses on determining the referent case scenario (business as usual) for the year 2021.
Overall & specific emissions in SEE
Our forecast anticipates an overall increase in CO2 emissions of almost 9% considering the referent business as usual scenario. Observing key market characteristics, a simple explanation to why carbon emissions are likely to rise can be deducted: the increase in demand will not be accompanied with a corresponding increase in the renewable energy portfolio. If the majority of the resulting difference in load will not be satisfied through imports, the SEE generation portfolio will have to rely on its thermal generation set mostly based on lignite fired units – this will, consequently, rise carbon emissions. There is not a great deal of modernisation projects in the region, while some new additions do not even comply to BAT principles (i.e. lignite based thermal power plant Stanari with an efficiency of just a few percentile points over 30). In other words, until the increase in renewable energy electricity production is higher than the increase in demand, carbon emissions will continue to rise.
Comparison of overall and specific CO2 emissions in SEE, 2017/2021
We identified the following five key factors influencing carbon emissions of the electricity sector: (1) electricity demand; (2) hydrological conditions; (3) generation portfolio evolution; (4) fuel prices and (5) carbon prices. In order to determine the gravity of their impact, a market based sensitivity analysis is conducted for the year 2021. Sensitivity cases are described in Table 1. Variations in parameters considered are relative to the referent scenario of the year 2021 (abbreviated R). In most cases the comparison is made between referent, optimal and pessimal scenario. Boundaries of hydrological conditions are assumed with regard to historical values during the past 15 years. They are considered through a variation of ±30% of useful water inflows. RES portfolios are assumed considering an equal ratio between types of sources per each country. Installed capacity was increased or decreased in order to respond to a ±20% variation in overall annual production. Fuel costs refer to oil, coal, lignite and natural gas prices, whether of domestic or imported commodities.
Referent case 2017
Referent case 2021
Demand lowered by 5%
Demand raised by 5%
Hydrological conditions optimal
Hydrological conditions pessimal
Fuel prices lower by 30%
Fuel prices higher by 30%
Emission cost of 0 €/tCO2
Emission cost of 20 €/tCO2
Emission cost of 40 €/tCO2
Emission cost of 60 €/tCO2
Market analysis sensitivity cases considered
Sensitivity analysis results
As expected, lower demand, favourable hydrological conditions, higher fuel prices and higher carbon costs all result in lower emissions. However, these factors have considerably different impacts on the level of overall emissions. Figure on the left reveals these impacts and highlights changes in carbon emissions compared to the referent case scenario.
Carbon emissions vs. key external factors
Carbon prices' effect on emissions
Potential carbon costs are given special consideration during the sensitivity analysis. As outlined, a variation of 0-60 €/tCO2 is considered. Having conducted the necessary iterations of the optimisation process, the gravity of several effects on the market caused by the increase in carbon prices is revealed. Three of the most significant effects are (1) raised electricity prices, (2) a shift towards environmentally more acceptable thermal power generation technologies and (3) lower CO2 emissions. Average marginal price during the course of the year for the 0 €/tCO2 scenario equalled 37.0 €/MWh. Raising carbon prices to 20 €/tCO2, 40 €/tCO2 and 60 €/tCO2 translated into average electricity prices of 45.1 €/MWh, 52.8 €/MWh and 65.3 €/MWh respectively. This corresponds to 21.9%, 17.0% and 23.8% increases for each 20 €/tCO2 change. Overall carbon costs, at maximum level considered (at 60 €/tCO2), equalled €5.7 billion. This carbon price increase facilitated 15.8% reduction of CO2 emissions, corresponding to 17.9 million tonnes of CO2.
Carbon prices’ influence on electricity prices and CO2 emissions
Generation mix implications
Naturally, the question of how the recorded reduction in emissions is achieved arises. Carefully observing the production mix reveals a shift towards gas power plants occurred. As some coal fired units remained online, a number failed to cope with changing market circumstances. This resulted in more gas-based electricity production and, consequently, lower emissions. Comparing 0 €/tCO2 to 60 €/tCO2 scenarios, reveals 26.9% lower production by coal fired units (31.8 TWh) and 936.9% higher gas fired electricity generation (31.2 TWh).
Coal to gas shift as caused by carbon price increase
The new energy paradigm puts significantly more emphasis on characteristics other than the potential financial benefit of an energy system. Apart from affordable, energy supply must also be secure and sustainable. As the energy sector has countless participants and influencing factors, it is very difficult to determine optimal development strategies that could satisfy all the criteria put in front of policymakers. More often, a combination of policies and a technologies is used and faces certain trade-offs to best address the surrounding territory’s potential and constraints. Energy sector faces significant uncertainties in forming new development strategies and building portfolios that are able to best suit consumer and system needs. However, one thing does seem certain – sustainable energy solutions will play a crucial role in the future of energy use. Achieving sustainability at affordable cost and secure supply will be a difficult task requiring a combination of policies, involving a string of participants and facing a number of trade-offs. It is a necessary step towards an environmentally sustainable system able to provide energy without lowering other aspects related to the quality of life.
Main goal of this research is to develop a framework able to compute carbon emissions of an electricity sector, but also a framework capable of forecasting emissions under different market terms whether with regard to hydrological conditions, variations in demand, fuel prices volatility, development scenarios or different policy approaches. Presented framework consists of a mathematical model supported with an optimisation software. Two basic building blocks of the mathematical model are the Karush–Kuhn–Tucker conditions and the quadratic hourly consumption curve. After calculating referent emissions for 2017, 2021 emissions are forecasted based on a number of presumptions regarding the evolution of electricity sectors in the region. Finally, a sensitivity analysis based on variations of several impact factors is conducted revealing their correlation to carbon emissions. Furthermore, the model presented allows simulation of different scenarios regarding the evolution of carbon prices. After compiling all research data, a coherent view on key differences is given.
Comparing boundary cases considered, four key conclusions can be drawn:
(1) an overall reduction of 18 Mt of CO2 is recorded;
(2) 31.2 TWh of electricity is produced by gas fired units instead of the coal/lignite fired portfolio and an additional quantity of electricity is imported;
(3) 28.3 €/MWh is the increase in average marginal electricity market price over a year-long period making the overall cost of €7.11 billion when paired with annual electricity demand;
(4) €5.7 billion is gathered through carbon allowances making the direct specific cost of CO2 avoided a staggering 318.9 €/tCO2 (€5.7 billion divided by 18 MtCO2). The term “cost of CO2 avoided” refers to the cost paid by the thermal generation portfolio for the CO2 emitted.
However, it should be noted that our analysis reveals an increase in electricity prices corresponding to the increase in carbon prices. In other words, higher carbon costs are simply transferred from thermal power plants to final consumers through the electricity market. When looking at the overall increase of electricity costs caused by higher carbon prices (an increase of €7.11 billion), the avoidance cost is even higher, at 397.8 €/tCO2. Presented findings do not dispute the necessity of imposing emission allowances, but do offer an interesting result – no matter how high carbon prices are, their effect in reducing emissions is somewhat limited. Naturally, higher carbon prices facilitate the increased use of gas fired electricity generation and cause a reduction in CO2 emissions. However, depending on system characteristics, these reductions do have boundaries. Two key questions should be properly addressed when assessing policies potentially influencing carbon prices:
(1) What is the acceptable limit of electricity price increase that consumers (commercial or residential) should pay in order to support the emission trading scheme?
(2) How to properly invest the money gathered by imposing carbon taxes in order to help facilitate the development and implementation of new sustainable solutions?
Looking at the results obtained, it can be seen that, without dramatically increasing prices of electricity to final consumers, an increase in carbon prices would not yield the benefits desired. Additionally, in a certain amount, without imposing carbon taxes on electricity imported to the countries of the ETS zone, production would shift from ETS member states to non-ETS countries due to unhealthy competition. Results of increasing carbon prices are noticeable, but looking at the direct cost-benefit ratio reveals it as far from acceptable. However, despite not yielding expected short-term results, if properly re-invested, carbon costs can provide a long-term benefit through financing new technological solutions. In addition, if investment costs of carbon capture and storage (CCS) technology would be lowered in the future to more acceptable levels, perhaps the ETS would be able to tip the scale and make them market competitive. As evidenced by numerous studies, in order to reduce the environmental footprint of the energy sector, while at the same time increase domestic industry development and provide a safe and affordable supply of energy – wind, solar, hydro, biomass, biogas and municipal solid waste (to name just a few) as renewable energy resources can play crucial role in creating a sustainable future for us all. Emerging technologies such as battery storage or CCS could also have a role to play in the transition as carbon intensity reduction strategies will require a number of different technological solutions. In this context, improving emission trading mechanisms and developing tools to help aid the process of estimating GHG emissions will play a crucial role on the path of creating a carbon-free sustainable energy system of the future.