Distribution of costs induced by the integration of RES-E power

This article focuses on the distribution of costs induced by the integration of electricity generation from renewable energy sources (RES-E). The treatment to distribute these costs on different market actors is crucial for its development. For this purpose, individual actors of electricity markets and several cost categories are identified. According to the defined cost structure, possible treatments to distribute the individual cost categories on different relevant actors are described. Finally, an evaluation of the cost distribution treatments based on an economic analysis is given. Economic efficiency recommends that clearly attributable (shallow) grid connection as well as (deep) grid costs are charged to the corresponding RES-E producer and that the RES-E producers are also charged the regulating power costs. However, deep grid integration costs should be updated to reflect evolving scarcities. Also regulating power costs should reflect actual scarcity and thus be symmetric and based on real-time prices, taking into account the overall system imbalance. Moreover, the time span between the closure of the spot market and actual delivery should be chosen as short as possible to enable accurate RES-E production forecasts.     

Renewable energy sources in European energy supply and interactions with emission trading

This paper presents a model-based approach, which allows to determine the optimised structure and operation of the EU-15 electricity supply under different political and economic framework conditions, with a focus on the integration of renewable energy sources for electricity generation (RES-E) in the EU-15 countries. The approach is designed to take into account the characteristics of power production from both renewable and conventional sources, including the technological and economic characteristics of existing plants as well as those of future capacity expansion options. Beyond that, fuel supply structures are modelled, as well as the international markets for power and CO₂-certificates with their restrictions. Thus, a profound evaluation of the exploitation of mid-term renewable potentials and an assessment of the market penetration of the various renewable power generation technologies under the (normative) premise of a cost-optimised evolution of the power system becomes possible. Results show that a promotion of renewable energies reduces the scarcity of CO₂-emission allowances and thus lowers marginal costs of CO₂ reduction up to 30% in 2030. Despite the higher overall costs, a diversification of the energy resource base by RES-E use is observed, as primarily natural gas and nuclear fuels are replaced.     

Modelling of auctioning mechanism for solar photovoltaic capacity

In this work, a modified optimisation model for the integration of renewable energy sources for power-generation (RES-E) technologies in power-generation systems on a unit commitment basis is developed. The purpose of the modified optimisation procedure is to account for RES-E capacity auctions for different solar photovoltaic (PV) capacity electricity prices. The optimisation model developed uses a genetic algorithm (GA) technique for the calculation of the required RES-E levy (or green tax) in the electricity bills. Also, the procedure enables the estimation of the level of the adequate (or eligible) feed-in-tariff to be offered to future RES-E systems, which do not participate in the capacity auctioning procedure. In order to demonstrate the applicability of the optimisation procedure developed the case of PV capacity auctioning for commercial systems is examined. The results indicated that the required green tax, in order to promote the use of RES-E technologies, which is charged to the electricity customers through their electricity bills, is reduced with the reduction in the final auctioning price. This has a significant effect related to the reduction of electricity bills.     

Flexibility in Europe's power sector — An additional requirement or an automatic complement?

By 2050, the European Union aims to reduce greenhouse gases by more than 80%. The EU member states have therefore declared to strongly increase the share of renewable energy sources (RES-E) in the next decades. Given a large deployment of wind and solar capacities, there are two major impacts on electricity systems: First, the electricity system must be flexible enough to cope with the volatile RES-E generation, i.e., ramp up supply or ramp down demand on short notice. Second, sufficient back-up capacities are needed during times with low feed-in from wind and solar capacities. This paper analyzes whether there is a need for additional incentive mechanisms for flexibility in electricity markets with a high share of renewables. For this purpose, we simulate the development of the European electricity markets up to the year 2050 using a linear investment and dispatch optimization model. Flexibility requirements are implemented in the model via ramping constraints and provision of balancing power. We found that an increase in fluctuating renewables has a tremendous impact on the volatility of the residual load and consequently on the flexibility requirements. However, any market design that incentivizes investments in least (total system) cost generation investment does not need additional incentives for flexibility. The main trigger for investing in flexible resources is the achievable full load hours and the need for backup capacity. In a competitive market, the cost-efficient technologies that are most likely to be installed, i.e., gas-fired power plants or flexible CCS plants, provide flexibility as a by-product. Under the condition of system adequacy, flexibility never poses a challenge in a cost-minimal capacity mix. Therefore, any market design incentivizing investments in efficient generation thus provides flexibility as an inevi complement.     

Assessment of solar electricity production in the United Arab Emirates

In this work the possible large-scale integration of photovoltaic (PV) systems and parabolic trough concentrated solar power (CSP) technologies in the United Arab Emirates (UAE) power system is investigated in technical, economic and environmental terms. The analysis takes into account the available solar potential for UAE and in particular for the Emirate of Sharjah. In order to identify the least-cost feasible option for each renewable energy source for power-generation (RES-E) technology, a parametric analysis is carried out by varying each RES-E candidate system capital cost. From the analysis it is evident that an alternative cost-effective technology to the installation of a 50 MWp PV system might be the utilisation of a 50 MWe parabolic trough CSP system with either a 14.5 h thermal storage system or a 24/7 operation. The advantages of the latter are the dispatchability and the increased electricity output due to the utilisation of a thermal storage system, which leads to higher amounts of annual CO₂ avoided emissions. However, the electricity selling prices are higher than the current UAE electricity tariffs; therefore, for the promotion of solar RES-E technologies in the UAE, relevant financial supporting mechanisms need to be developed such as feed-in tariffs or feed-in premiums.     

Co-firing biomass with coal for electricity generation—An assessment of the potential in EU27

The European Union aims to increase bioenergy use. Co-firing biomass with coal represents an attractive near-term option for electricity generation from renewable energy sources (RES-E). This study assesses the near-term technical potential for biomass co-firing with coal in the existing coal-fired power plant infrastructure in the EU27 Member States. The total technical potential for RES-E from biomass co-firing amounts to approximately 50–90 TWh/yr, which requires a biomass supply of approximately 500–900 PJ/yr. The estimated co-firing potential in EU27 amounts to 20–35% of the estimated gap between current RES-E production and the RES-E target for 2010. However, for some member states the national co-firing potential is large enough to fill the national gap. The national biomass supply potential is considerably larger than the estimated biomass demand for co-firing for all member states. About 45% of the estimated biomass demand for co-firing comes from plants located close to the sea or near main navigable rivers and indicates the possibility for biomass import by sea transport. Thus, biomass co-firing has the potential to contribute substantially to the RES-E development in EU27.     

Cost/benefit analysis of transmission grid expansion to enable further integration of renewable electricity generation in Austria

This paper elaborates on the costs and benefits of expanding the Austrian transmission system and the implementation of innovative grid-impacting technologies (e.g. flexible AC transmission systems (FACTS), dynamic line rating (DLR)) to support further integration of renewable energy sources for electricity generation (RES-E). Therefore, a fundamental market model has been developed - respecting DC load flows - and applied for analysing different future scenarios, notably for the time horizon 2020, 2030 and 2050. Up to 2020 and 2030, special focus is put on the finalisation of the so-called “380 kV-level transmission ring” in Austria to enable enhanced RES-E integration. The results confirm that transmission power line expansion in the states of Salzburg and Carinthia is important to connect imports from Germany with pumped hydro storage capacities, on the one hand, and the wind farms in the east with the pumped hydro storages in the western part of Austria, on the other hand. For 2050, the results indicate that the implementation of FACTS and DLR can reduce RES-E curtailment significantly.     

Decarbonizing Europe's power sector by 2050 — Analyzing the economic implications of alternative decarbonization pathways

The European Union aims to reduce greenhouse gas emissions by 80–95% in 2050 compared to 1990 levels. The transition towards a low-carbon economy implies the almost complete decarbonization of Europe's power sector, which could be achieved along various pathways. In this paper, we evaluate the economic implications of alternative energy policies for Europe's power sector by applying a linear dynamic electricity system optimization model in over 36 scenarios. We find that the costs of decarbonizing Europe's power sector by 2050 vary between 139 and 633 bn €₂₀₁₀, which corresponds to an increase of between 11% and 44% compared to the total system costs when no CO₂ reduction targets are implemented. In line with economic theory, the decarbonization of Europe's power sector is achieved at minimal costs under a stand-alone CO₂ reduction target, which ensures competition between all low-carbon technologies. If, however, renewable energies are exempted from competition via supplementary renewable energy (RES-E) targets or if investments in new nuclear and CCS power plants are politically restricted, the costs of decarbonization significantly rise. Moreover, we find that the excess costs of supplementary RES-E targets depend on the acceptance of alternative low carbon technologies. For example, given a complete nuclear phase-out in Europe by 2050 and politically implemented restrictions on the application of CCS to conventional power plants, supplementary RES-E targets are redundant. While in such a scenario the overall costs of decarbonization are comparatively high, the excess costs of supplementary RES-E targets are close to zero.     

Fast market penetration of energy technologies in retrospect with application to clean energy futures

The fast penetration of energy technologies in the past was analyzed and applied to investigate the prospects of new energy technologies. The results show that single energy sources have obtained quite a dominant position in the past. In the USA, at one time both oil and coal each represented over half of all the yearly additions to energy capacity for more than half a century and reached a dominant position in overall energy production. Oil showed a similar dominance on a global scale. For two decades nuclear power represented one third of all the new electricity added worldwide and over 60% in the countries possessing nuclear power. In some countries nuclear grew to around half of all electricity in less than just 10 years. Applying these empirical observations to new renewables and assuming similar growth conditions as for the old technologies, the share of renewable electricity could grow from its present 19% to 60% by 2050, which would drop the baseline CO₂ emissions by 27%. The share of new renewables of all electricity would come up to 42%. The rate of adoption of these new technologies would not exceed that of oil or nuclear in the past, but they would need to dominate new electricity investments from 2030 onwards. A hypothetical fast-track case for solar photovoltaics, assuming an expansion similar to that seen in the case of nuclear and oil, would lead to a 20–25% share of all electricity in 2050. An important observation is that the fast and high penetration of energy technologies implies, in most cases, a full lock-in into these, requiring a preferential position regarding investments and a favorable long-term policy framework.     

Cost effects of international trade in meeting EU renewable electricity targets

The European market for renewable electricity received a major stimulus from the adoption of the Directive on the Promotion of Renewable Electricity. The Directive specifies the indicative targets for electricity supply from renewable energy sources (RES-E) to be reached in European Union (EU) Member States in the year 2010. It also requires Member States to certify the origin of their renewable electricity production. This article presents a first EU-wide quantitative evaluation of the effects of meeting the targets, using an EU-wide system for tradable green certificates (TGC). We calculate the equilibrium price of green certificates and identify which countries are likely to export or import certificates. Cost advantages of participating in such an EU-wide trading scheme are determined for each of the Member States. Moreover, we identify which choice of technologies results in meeting targets at least costs. Results are obtained from a model that quantifies the effects of achieving the RES-E targets in the EU with and without trade. The article provides a brief insight in this model as well as the methodology that was used to specify cost potential curves for renewable electricity in each of the 15 EU Member States. Model calculations show that within the EU-wide TGC system, the total production costs of the last option needed to satisfy the overall EU RES-E target equals 9.2 eurocent/kWh. Assuming that the production price of electricity on the European power market would equal 3 eurocent/kWh in the year 2010, the indicative green certificate price equals 6.2 eurocent/kWh. We conclude that implementation of an EU-wide TGC system is a cost-efficient way of stimulating renewable electricity supply.     

Assessing the strength and effectiveness of renewable electricity feed-in tariffs in European Union countries

In the last two decades, feed-in tariffs (FIT) have emerged as one of the most popular policies for supporting renewable electricity (RES-E) generation. A few studies have assessed the effectiveness of RES-E policies, but most ignore policy design features and market characteristics (e.g. electricity price and production cost) that influence policy strength. We employ 1992–2008 panel data to conduct the first econometric analysis of the effectiveness of FIT policies in promoting solar photovoltaic (PV) and onshore wind power development in 26 European Union countries. We develop a new indicator for FIT strength that captures variability in tariff size, contract duration, digression rate, and electricity price and production cost to estimate the resulting return on investment. We regress this indicator on added RES-E capacity using a fixed effects specification and find that FIT policies have driven solar PV development in the EU. However, this effect is overstated without controlling for country characteristics and is concealed without accounting for policy design. We do not find robust evidence that FIT policies have driven wind power development. Overall, we show that the interaction of policy design, electricity price, and electricity production cost is a more important determinant of RES-E development than policy enactment alone.     

Cost of power interruptions to electricity consumers in the United States (US)

The massive electric power blackout in the northeastern US and Canada on August 14–15, 2003 catalyzed discussions about modernizing the US electricity grid. Industry sources suggested that investments of $50–100 billion would be needed. This work seeks to better understand an important piece of information that has been missing from these discussions: what do power interruptions and fluctuations in power quality (power-quality events) cost electricity consumers? We developed a bottom-up approach for assessing the cost to US electricity consumers of power interruptions and power-quality events (referred to collectively as “reliability events”). The approach can be used to help assess the potential benefits of investments in improving the reliability of the grid. We developed a new estimate based on publicly available information, and assessed how uncertainties in these data affect this estimate using sensitivity analysis.     

Supply amount and marginal price of renewable electricity under the renewables portfolio standard in Japan

The Renewables Portfolio Standard (RPS) in Japan requires that approximately 1.35% of each retail supplier's electricity sales in FY2010 come from renewable energy sources (RES), for example, photovoltaics, wind, biomass, geothermal, and small hydropower. To help retail suppliers and renewable generators develop effective strategies, this study provides a quantitative analysis of the impact of this measure. We assume the supply conditions for electricity generation from renewable energy sources (RES-E) based on regional resource endowments, and we derive the cost-effective compositions of renewable portfolios, RES-E certificate prices, and additional costs to retail suppliers. The future prospects of RES-E are assessed based on technology, region, and year up to FY2010. The analysis reveals that wind power and biomass power generated from municipal waste will provide the majority of the total supply of RES-E under the RPS. It also indicates that the marginal price of RES-E certificates will be approximately 5.8 JPY/kWh (5.2 USc/kWh) in FY2010, in the case wherein the marginal price of electricity is assumed to be 4 JPY/kWh (3.6 USc/kWh). In order to elaborate on this further, sensitivity analyses for some parameters of RES and the price of electricity are provided. The dynamic supply curves of RES-E certificates are also indicated.     

Pros and cons of exposing renewables to electricity market risks—A comparison of the market integration approaches in Germany,Spain, and the UK

The article examines how renewable electricity (RES-E) producers are integrated into the electricity market under the support legislations and regulatory frameworks of Germany, Spain, and the UK. Focus is on wind power, which faces the highest market integration challenge of all RES-E. The analysis shows that the three countries follow contrasting approaches of exposing RES-E producers to the market risks of forward electricity markets, balancing markets and system planning requirements. Risk exposure is highest in the UK and lowest in Germany. From a policy maker's perspective, there is a trade-off between a “high risk” and a “low risk” approach. When RES-E face high market risks, a higher level of financial support is required to stimulate RES-E development than in a low risk environment, but the exposure to market risks may also give an incentive to make efficient use of the respective market, thus limiting the indirect costs to society. The special characteristics of wind energy, however, put natural limits to the response of wind power plants to market prices and locational price signals and will increasingly influence electricity markets and grid infrastructure. These interdependencies should be recognised in the design of RES-E policies and market regulations.     

Wind power planning: assessing long-term costs and benefits

In the following paper, a new and straightforward technique for estimating the social benefit of large-scale wind power production is presented. The social benefit is based upon wind power's energy and capacity services and the avoidance of environmental damages. The approach uses probabilistic load duration curves to account for the stochastic interaction between wind power availability, electricity demand, and conventional generator dispatch. The model is applied to potential offshore wind power development to the south of Long Island, NY. If natural gas combined cycle and integrated gasifier combined cycle (IGCC) are the alternative generation sources, wind power exhibits a negative social benefit due to its high capacity cost and the relatively low emissions of these advanced fossil-fuel technologies. Environmental benefits increase significantly if charges for CO₂ emissions are included. Results also reveal a diminishing social benefit as wind power penetration increases. The dependence of wind power benefits on CO₂ charges, and capital costs for wind turbines and IGCC plant is also discussed. The methodology is intended for use by energy planners in assessing the social benefit of future investments in wind power.     

Implications of technological learning on the prospects for renewable energy technologies in Europe

The objective of this article is to examine the consequences of technological developments on the market diffusion of different renewable electricity technologies in the EU-25 until 2020, using a market simulation model (ADMIRE REBUS). It is assumed that from 2012 a harmonized trading system will be implemented, and a target of 24% renewable electricity (RES-E) in 2020 is set and met. By comparing optimistic and pessimistic endogenous technological learning scenarios, it is found that diffusion of onshore wind energy is relatively robust, regardless of technological development, but diffusion rates of offshore wind energy and biomass gasification greatly depend on their technological development. Competition between these two options and (existing) biomass combustion options largely determines the overall costs of electricity from renewables and the choice of technologies for the individual member countries. In the optimistic scenario, in 2020 the market price for RES-E is 1 €ct/kWh lower than in the pessimistic scenario (about 7 vs. 8 €ct/kWh). As a result, total RES-E production costs are 19% lower, and total governmental expenditures for RES-market stimulation are 30% lower in the optimistic scenario.     

Cost‐optimized allocation of wind power investments: a Nordic–German perspective

Using a linear cost minimization model with a 1 h time resolution, we investigated the influence of geographic allocation of wind power on large‐scale wind power investments, taking into account wind conditions, distance to load, and the nature of the power system in place (i.e. power generation and transmission capacities). We employed a hypothetical case in which a 20% wind power share of total electricity demand is applied to the Nordic–German power system. Free, i.e. geographically unrestricted, allocation of new wind power capacity is compared with a case in which national planning frameworks impose national limitations on wind power penetration levels. Given the cost assumptions made in the present work, the prospect of increasing the wind power capacity factor from 20 to 30% could motivate investments in transmission capacity from northern Scandinavia to continental Europe. The results obtained using the model show that the distribution of wind farms between regions with favorable wind conditions is dependent upon two factors: (i) the extent to which existing lines can be used to transmit the electricity that results from the new wind power and (ii) the correlation for wind power generation between the exporting region and the wind power generation already in place. In addition, the results indicate that there is little difference, i.e. just over 1%, in total yearly cost between the free allocation of new wind power and an allocation that complies with national planning frameworks. However, on a national level, there are significant differences with respect to investments in transmission and wind power capacities and the replacement of conventional power generation. Copyright © 2012 John Wiley & Sons, Ltd.     

Capacity payment impact on gas-fired generation investments under rising renewable feed-in — A real options analysis

We assess the effect of capacity payments on investments in gas-fired power plants in the presence of different degrees of renewable energy technology (RET) penetration. Low variable cost renewables increasingly make investments in gas-fired generation unprofitable. At the same time, growing feed-in from intermittent RETs amplifies fluctuations in power generation, thus entailing the need for flexible buffer capacity—currently mostly gas-fired power plants. A real options approach is applied to evaluate investment decisions and timing of a single investor in gas-fired power generation. We investigate the necessity and effectiveness of capacity payments. Our model incorporates multiple uncertainties and assesses the effect of capacity payments under different degrees of RET penetration. In a numerical study, we implement stochastic processes for peak-load electricity prices and natural gas prices. We find that capacity payments are an effective measure to promote new gas-fired generation projects. Especially in times of high renewable feed-in, capacity payments are required to incentivize peak-load investments.     

Economic modelling of price support mechanisms for renewable energy: Case study on Ireland

The Irish Government is considering its future targets, policy and programmes for renewable energy for the period beyond 2005. This follows a review in 2003 of policy options that identified a number of different measures to stimulate increased deployment of renewable energy generation capacity. This paper expands this review with an economic analysis of renewable energy price support mechanisms in the Irish electricity generation sector. The focus is on three primary price support mechanisms quota obligations, feed in tariffs and competitive tender schemes. The Green-X computer model is utilised to characterise the RES-E potential and costs in Ireland up until, and including, 2020. The results from this dynamic software tool are used to compare the different support mechanisms in terms of total costs to society and the average premium costs relative to the market price for electricity. The results indicate that in achieving a 20% RES-E proportion of gross electricity consumption by 2020, a tender scheme provides the least costs to society over the period 2006–2020 but only in case there is limited or no strategic bidding. Considering, however, strategic bidding, a feed-in tariff can be the more efficient solution. Between the other two support mechanisms, the total costs to society are highest for feed-in-tariffs (FIT) until 2013, at which point the costs for the quota system begin to rise rapidly and overtake FIT in 2014–2020. The paper also provides a sensitivity analysis of the support mechanism calculations by varying default parameters such as the interim (2010) target, the assumed investment risk levels and the amount of biomass co-firing. This analysis shows that a 2010 target of 15% rather than 13.2% generates lower costs for society over the whole period 2006–2020, but higher costs for the RES-E strategy over the period 2006–2010.     

Environmental and economic appraisal of power generation capacity expansion plan in Nigeria

The power sector in Nigeria is undergoing structural reforms aimed at improving and expanding the current grid generation capacity and distribution network. The Government has injected huge funds into this sector while also granting licences to private companies for the provision of electricity. It is also aiming to increase electricity generation capacity to 25,000 MW by 2020 from the current installed capacity of 6500 MW while also pledging to connect 75% of the population to the grid from the current 40% by 2025. This paper sets out to analyse the implications of the energy policy in Nigeria and presents the life cycle environmental and economic analysis of the current and future electricity sector. The results show that all the life cycle impacts and economic costs increase significantly over the time-period (2003–2030), but at different rates depending on the types of technologies deployed. Renewables such as large hydro and solar proposed by the Government have a potential to reduce the overall life cycle environmental impacts from the electricity mix, considering their lower environmental impacts compared to fossil-fuels. However, this requires a five-fold increase in grid investments from the current US$1.7 billion per year to US$9.40 billion by 2030.