Investment In Generation Capacity Research Articles

Assessment of electricity network investment for the integration of high RES shares: A Spanish-like case study

In the course of the energy transition, the EU member states’ National Energy and Climate Plans seek to install significant amounts of intermittent renewable generation capacity over this decade. Previous studies underline the social, political, and economic benefits of the electricity sector decarbonisation. The economic analysis of renewable energy sources (RES) integration is commonly performed with single-bus generation expansion models that seek the cost-optimal expansion of RES generation capacity to reduce operational expenses. However, electricity grids will require investments to adapt to the integration of high amounts of RES capacity. This paper contrasts the cost-optimal generation capacity mix obtained from a single-bus expansion model with a conservative estimation of electricity network investment requirements for an exemplary Spanish-like case study. RES network investment costs are put in context with an alternative non-RES generation expansion pathway. Network investment costs considered include expansion costs for both transmission and distribution grids. Electricity network expansion costs represent 6 to 10% of the corresponding generation capacity investment. Despite increasing network investment costs, the integration of high RES shares into electricity grids reduces operating costs when compared to non-RES pathways. Fuel and emission savings exceed total investments (generation capacity, network expansion, and connection costs). • We quantify the grid investments needed to integrate high amounts of RES. • Results show that RES drive significant grid expansion and connection costs. • However, incremental grid investments represent only 6%–10% of RES investment costs. • RES-driven reduction in operating costs compensate for incremental grid costs. • High RES penetration is found to reduce total system costs (investment + operation).

The Role of BECCS in Achieving Climate Neutrality in the European Union

The achievement of climate neutrality in the European Union by 2050 will not be possible solely through a reduction in fossil fuels and the development of energy generation from renewable sources. Large-scale implementation of various technologies is necessary, including bioenergy with carbon capture and storage (BECCS), carbon capture and storage (CCS), and carbon capture and utilisation (CCU), as well as industrial electrification, the use of hydrogen, the expansion of electromobility, low-emission agricultural practices, and afforestation. This research is devoted to an analysis of BECCS as a negative emissions technology (NET) and the assessment of its implementation impact upon the possibility of achieving climate neutrality in the EU. The modelling approach utilises tools developed within the LIFE Climate CAKE PL project and includes the MEESA energy model and the d-PLACE CGE economic model. This article identifies the scope of the required investment in generation capacity and the amount of electricity production from BECCS necessary to meet the greenhouse gas (GHG) emission reduction targets in the EU, examining the technology’s impact on the overall system costs and marginal abatement costs (MACs). The modelling results confirm the key role of BECCS technology in achieving EU climate goals by 2050.

Environmental agreements, research and technological spillovers

This paper considers different contracts of international environmental agreements in a dynamic game in which countries choose emissions, R&D investments and investments in renewable energy generation capacity. R&D investments cause technological spillovers. For the different contracts the size of the stable coalition is analyzed. It turns out that both cooperation over R&D investments and technology transfers within the coalition may enhance the size of stable coalitions. In an empirical calibration, the stable coalition of the complete contract is quite small. An incomplete contract over emission leads to larger stable coalitions which can be further enlarged by a technology transfer within the coalition. An incomplete contract over emissions and R&D investments is the best performer and yields the largest stable coalition up to the grand coalition. The incomplete contract over emissions and R&D investments is pareto-superior to all other contracts and may even be first best.

Merchant transmission in single-price electricity markets with cost-based redispatch

Transmission expansion is a complex problem in energy market design and research has not yet provided a market-based solution that is superior to a (partly) regulated approach. Furthermore, markets with a single market clearing price lack regional incentives for system friendly generation or transmission capacity expansion. In this paper, we propose a market design for transmission expansion that can be implemented in single-price markets with cost-based redispatch and we describe its properties. We show that our market solution is incentive compatible, satisfies the ’beneficiary pays’ requirement and leads to a welfare optimal grid expansion otherwise achieved by an integrated optimization approach of a benevolent grid operator. We apply the mechanism to the German electricity system in 2018, 2019 and 2030 as an example and show that transmission capacity expansion is greatly reduced using the mechanism instead of a no-congestion regulation. We also test the robustness of the approach to erroneous generation capacity expectations and find that the impact on economic results is limited. Finally, we extend our approach to include congestion reducing generation capacity investment and discuss the strategic effects on a 6-node reference grid.

Excessive entry and investment in deregulated markets: Evidence from the electricity sector

The staggered and partial restructuring of state electricity markets beginning in 1996 is leveraged to identify the effect of entry deregulation on investment in generation capacity during the U.S. Gas Boom. Using synthetic control to construct the counterfactual outcome, this paper finds restructuring led to a 17 percent increase in capacity beyond the counterfactual in the seven years following restructuring. The overinvestment of the electricity industry is consistent with market coordination failure, contagion and low real interest rates, leading to an environmental welfare gain of $27.6 billion but overall net welfare loss of $18.85 billion.

Optimizing regional electricity trading with Carbon Emissions Pinch Analysis

The global effort to decarbonize electricity production requires the concurrent phaseout of fossil fuel-fired power plants coupled with the installation of new renewable energy capacity. The requirement for the latter capacity may be prohibitive in cases where deep greenhouse gas emissions cuts are sought. Electricity trading among countries provides an opportunity to aggregate electricity sources and demands and reduce incremental new renewable energy generation. Carbon emissions limits of each country can be met if a renewable energy certification system is in place. In this work, modified Carbon Emissions Pinch Analysis (CEPA) approaches were developed to determine the minimum renewable energy target for a group of countries with an electricity trading agreement. CEPA is implemented here both graphically and via the Automated Targeting Model (ATM). The effectiveness of this approach for carbon-constrained energy planning is illustrated using three case studies, which include a case study based on countries in the Association of Southeast Asian Nations (ASEAN). The case study results show that electricity trading can reduce new aggregated renewable energy capacity by 9 TWh. Furthermore, the case studies demonstrate reduced investments in renewable energy generation capacity and avoiding energy assets from being stranded in some cases.

Research on European capacity cost recovery mechanism and its experience to China’s power market construction

This paper makes an in-depth study of generation capacity cost recovery issues that have been, or are being faced, in European countries and summarizes its experience to China during the construction of competitive power markets. Firstly, the paper explains the idea and principle of capacity cost recovery mechanisms in EU, which are policy instruments to ensure adequate investment in generation capacity, then analyses the obstacles to the realization of capacity cost recovery in the energy-only market. Then, the paper divides the European capacity cost recovery mechanism into five categories: strategic reserve, capacity obligation, capacity auction, reliability option and capacity payment, and expounds the operation flow of the mechanisms respectively in detail. Thirdly, the paper studies the possible impact of the capacity cost recovery mechanism on the electricity market. Finally, the paper summarizes the practical experience of European capacity cost recovery mechanisms and lay a foundation for the design of generation capacity cost recovery mechanism in China.

Electric vehicle adoption in a market environment in 2035: The impact of market penetration and charging strategies

This paper analyzes the profitability for adopting battery electric vehicles (BEVs) in the year 2035 accounting for different charging options and their feedback on the electricity sector. We propose a multi-level equilibrium model for the electricity market to determine charging costs, which incorporates endogenous determination of generation capacity investment, network expansion and redispatch, including demand for large-scale deployment of BEV mobility. The model allows to investigate the impact of BEV mobility and different charging options on the electricity system and its endogenous feedback on charging prices. For different degrees of BEV penetration, we calibrate our model for the German electricity market in 2035 and consider various charging options: (i) non-smart charging based on a standard charging profile, (ii) smart charging, where the charging load can be shifted throughout the entire day to provide flexibility to the system and (iii) a mixed charging strategy, where smart charging is only possible during night hours. We then analyze the impact of those charging strategies on charging and electricity prices, generation and transmission investment, RES curtailment, CO2 emissions and total system cost. In a next step, those endogenously determined charging prices are incorporated in a total cost of ownership analysis to investigate BEV profitability. Our results reveal that larger BEV penetration yields lower CO2 emissions even in those scenarios with smaller availability of green electricity production. Charging prices and resulting CO2 emission substantially depend on the chosen charging strategy. Even for large-scale deployment of BEV, however, electricity prices will remain comparatively low and thus charging prices in all considered scenarios account only for a small fraction of total vehicle cost. Thus, the profitability of adopting an electric vehicle crucially depends on the initial investment cost and potentially granted public support schemes.

The potential of industrial electricity savings to reduce air pollution from coal-fired power generation in China

Coal-intensive power supply systems, along with a fast-growing electricity demand driven by industry has caused serious air pollution and health concerns. These concerns are particularly prominent in countries where electricity use is likewise dominated by industry and heavily dependent on coal-based electricity. A more efficient industry and coal-free electricity systems are the core components of the United Nations 2030 Agenda for Sustainable Development. Previous studies rarely reflect on the impacts of the electricity savings of industrial consumers on the electricity supply sector with respect to future air emission changes, and also neglect the potential benefits of reducing investments in new generation capacity. Here, a comprehensive modeling framework is newly developed to quantify the connections of electricity savings, coal-based electricity systems, air pollutant emissions, and control investments in China, a country exposed to poor air quality. The modeling framework includes 175 energy efficiency technologies (covering multiple industrial sectors) and detailed information of power generation units (thermal efficiency, environmental performance, and lifespan), and allows for unit-by-unit assessment. We find that industrial efficiency improvements can significantly decrease the dependence on coal-fired power generation, particularly the most polluting power fleet. Efficient use of electricity in industry can drive all small high-polluting coal generation units (i.e. units below 300 MW, in total 753 units) to be phased out and effectively curb less efficient coal-fired plants to come online in China. Meanwhile, the air pollutant emissions can be significantly avoided because of the closed coal-fired power units. Developed cost portfolios demonstrate that improving industrial energy efficiency is more cost-effective than installing flue gas controls in coal-fired plants. We further reveal that a sustainable industry could contribute to climate change mitigation even if less remarkable than air quality improvement, while enabling the expansion of intermittent renewable power supply.

Electricity Markets in the Resource-Rich Countries of the MENA: Adapting for the Transition Era

The Middle East and North Africa’s (MENA) resource-rich economies are pursuing two parallel strategies in their electricity sectors: (i) increasing and integrating renewables into their power generation mix to mitigate the impact of rising domestic oil and gas demand on their economies and boost hydrocarbon export capacities; and (ii) undertaking power sector reforms to attract investment in generation capacity and networks, remove subsidies, and improve operational efficiency. These goals imply that the design of reforms (including regulations governing wholesale and retail markets and networks) needs to be carried out with a view to a rising share of non-dispatchable resources. The lack of an integrated approach to simultaneously address these two strategies is likely to lead to several misalignments between renewables and various components of future electricity markets, as the share of intermittent resources increases in the generation mix. The key challenge is that the ‘ultimate model’ capable of reconciling these two goals is as yet unknown, and is still evolving, due to uncertainties around the development of technologies, institutions, and consumer preferences. We argue that resource-rich MENA countries can, however, move towards adopting a transition model of electricity markets, the individual elements of which can be adapted to suit either centralized or decentralized future electricity sector outcomes. We outline the key components of this model for the wholesale market, retail market, and network regulation, considering governments’ objectives and the specific contexts of the countries in the region.

Emissions reduction in a second-best world: On the long-term effects of overlapping regulations

Industrialized countries around the world have set ambitious climate targets and face the challenge that existing mechanisms for CO2 pricing alone are not sufficient to achieve the desired level of ambition. In a multi-level electricity market model that captures investments in grid and generation capacities as well as electricity trading, we analyze different policy approaches to curb emissions by phasing out emission-intensive technologies, expanding renewables or by simply tightening CO2 pricing. We extend existing modelling approaches to endogenize (welfare-optimal) expansion of renewable energy capacities, taking into account the respective grid expansion necessary for a particular expansion path. Applying the approach to the German electricity market shows that both, the strengthening of the incentives from emissions trading through a minimum CO2 price as well as a forced complete coal exit lead to a significant additional decrease in emissions. The stepwise coal phase-out as decided in Germany, on the other hand, does not come close to achieving this reduction in emissions, largely due to the sequence of the phase-out decided (first hard coal, then lignite). The avoided CO2 emissions are accompanied by significant welfare gains in the respective scenarios. Further welfare gains can be achieved through a system-optimal expansion of renewables, especially because grid expansion can be avoided. We also consider different ways to remunerate renewables for all scenarios. It turns out that the renewable generators’ revenues from the electricity market together with the revenues from CO2 pricing are fully sufficient to finance renewables.

The impact of neighboring markets on renewable locations, transmission expansion, and generation investment

Many long-term investment planning models for liberalized electricity markets either optimize for the entire electricity system or focus on confined jurisdictions, abstracting from adjacent markets. In this paper, we provide models for analyzing the impact of the interdependencies between a core electricity market and its neighboring markets on key long-run decisions. This we do both for zonal and nodal pricing schemes. The identification of welfare optimal investments in transmission lines and renewable capacity within a core electricity market requires a spatially restricted objective function, which also accounts for benefits from cross-border electricity trading. This leads to mixed-integer nonlinear multilevel optimization problems with bilinear nonconvexities for which we adapt a Benders-like decomposition approach from the literature. In a case study, we use a stylized six-node network to disentangle different effects of optimal regional (as compared to supra-regional) investment planning. Regional planning alters investment in transmission and renewable capacity in the core region, which affects private investment in generation capacity also in adjacent regions and increases welfare in the core region at the cost of system welfare. Depending on the congestion-pricing scheme, the regulator of the core region follows different strategies to increase welfare causing distributional effects among stakeholders.

Renewable electricity generation target setting in developing countries: Modeling, policy, and analysis

Many countries have set renewable energy targets in their electricity supply mix to encourage investments in renewable energy technologies. In developing countries, however, many of such targets are either abandoned or fall far short of the target date, primarily due to issues of financing, cost of electricity, and level of unmet demand. This paper presents a Generation Expansion Planning model that can be used to assess such issues when setting a renewable electricity generation target. In particular, the model can be used by developing countries to set renewable electricity generation targets that are in line with their financial ability and thus, stand a higher chance of being achieved. Additionally, the analysis offered can inform developing countries of the cost and benefits of a renewable electricity generation target policy. The usefulness of the model is demonstrated using Ghana as a case. The results indicate that Ghana will need a budget of not less than 1% of its GDP for generation capacity investment if it desires to achieve its 10% renewable electricity generation target by 2030 while keeping unmet demand at reasonable levels. If Ghana however enforces the target at its current capacity investment levels, it risks raising unmet demand levels by an average of 4% per year and cost of electricity provision by about US$224 million annually between 2019 and 2030 when compared to the absence of a renewable electricity generation target.

Coordination of risk-based generation investments in conventional and renewable capacities in oligopolistic electricity markets: A robust regulatory tool

Investment in new generation capacity is considerably affected by issues such as regulatory-determined incentives, techno-economic uncertainties and financial risks. In addition, increased penetration of renewables such as wind capacities resulting in decreased market prices, leads to the augmented risk of investing in conventional generations such as thermal technologies, which may hamper generation adequacy. Thus, to meet regulatory goals for adequacy and environmental considerations, regulators should determine investment incentives considering targets for techno-environmental issues and generation investors’ risks. So, this paper presents a bi-level robust regulatory model, in which regulator in the first level designs incentives considering generation companies’ (GENCOs’) investment response to regulatory decisions. In the second level, a robust game-theoretic model is considered to capture interactions between risk-averse GENCOs, facing uncertainties such as rivals’ behavior and nondispatchable generations. The effectiveness of proposed model is demonstrated by IEEE-RTS and ERCOT test systems and the results are compared with those obtained in the deterministic cases. As the results show, capacity payments and feed-in premiums should be coordinately designed to meet regulatory targets for techno-environmental conditions. Besides, more levels of uncertainties lead to designing more levels of investment incentives with respect to the deterministic case. Moreover, the more is the level of GENCOs’ risk-aversion, the more is the cost of designed incentives for promising regulatory targets considering GENCOs’ risk-hedging.

An incentive mechanism for generation capacity investment in a price-capped wholesale power market

In electricity markets, market rules such as price caps defer proper investment in generation. The resulting generation mix is therefore sub-optimal if compared to the one that maximizes social welfare. In this paper, an incentive mechanism for a price-capped multi-area energy only market is proposed. The market model is posed as a mixed complementarity problem using the optimality conditions of all the individual players that participate in the multi-area electricity market. The resulting equilibrium problem is solved using a decomposition approach based on the Alternating Direction Method of Multipliers. The proposed solution algorithm takes advantage of the multi-area structure of the problem and outperforms state-of-the-art practices for solving these types of problems.

Long-run system value of battery energy storage in future grids with increasing wind and solar generation

With declining costs of battery storage, there is growing interest to deploy them in power systems to provide multiple grid services that directly support integration of variable renewable energy (VRE) generation. Here, we assess the holistic system value of energy storage in future grids with increasing wind and solar generation. We also identify the major sources of storage value and their dynamics under different system settings and at increasing storage and wind and solar penetration levels. We use a high temporal resolution capacity expansion model to study least-cost integration of storage in two variants of an abstract power system that is populated with load and VRE profiles consistent with the U.S. Northeast (North) and Texas (South) regions. For both systems, storage value originates primarily from deferring investments in generation capacity (VRE, natural gas) and transmission, and generally declines with increasing storage penetration. Increasing VRE penetration from 40% to 60% increases the value of storage, but only enough to make storage capacity up to 4% of peak demand cost-effective at current Lithium-ion capital costs. With future capital costs of $150/kWh for 4 h duration storage, the cost-effective storage penetration ranges between 4% and 16% of peak demand across the system scenarios studied here. Storage substitution of natural gas capacity is dependent on the VRE resource mix and penetration level, but is less than 1 GW per GW of storage added for the durations (2, 4 or 8 h) considered here. Increasing storage duration increases storage value in some cases, but this increase in value may be insufficient to compensate for the increase in capital cost per kW even under the future cost scenario.

Demand response in electricity generation planning

In this research, a simulation model is proposed to study the impact of consumer response rate on capacity and production planning. Different generation technologies such as base-load generation technologies and intermittent renewable energy technologies are considered. The simulation results show that the impact of DR depends on market price, the degree of demand elasticity, and the marginal cost of generation. As the rate of consumer response increases, investment in peak generation capacity becomes economically infeasible.

The dynamics of political power: The socio-technical transition of California’s electricity system to renewable energy

Global electricity generation depends on fossil fuels as a primary fuel and the negative environmental consequences of fossil fuel combustion are well known. This makes transitioning electricity generation to renewable energy sources a critical component of climate change mitigation. Energy transitions involve complex socio-technical systems, extending beyond economics or policy to include societal relationships with energy such as processes of manifesting societal will as policy decisions. Yet current energy-economy-climate-models are economy-policy centric and fail to include such socio-technical feedbacks in energy transition dynamics, especially the influence of policy formation on the rate of energy transitions. This missing feedback is incorporated into a system dynamics model of California’s electricity generation. The model is grounded in the advocacy coalition framework and examines competition between pro-fossil and pro-renewable interest’s influence on policy formation dynamics. Results show policy volatility, where competition drives inconsistent policy enactment and lifespan. This impacts transition dynamics as policies influence profitability analyses, and subsequent decisions in new generation capacity investments. Political lock-in was hypothesized to be the most critical influence on transition dynamics, as well-funded pro-fossil policy manipulation creates barriers to renewable energy that green advocacy coalitions struggle to overcome. However, results show this is less influential than anticipated and carbon lock-in, defined as the long lifespan of fossil fuel technologies, is also a critical driver of transition rates. Early retirement of fossil fuel electricity generation technologies allows current investment dynamics to favor higher capacities of renewables. This is a novel finding, and an open area for future research.

Exploring investment potential in a context of nuclear phase-out uncertainty: Perfect vs. imperfect electricity markets

In view of the ongoing nuclear power debate in Europe, we analyze how uncertainty about a nuclear phase-out affects investment capacity decisions by Belgian electricity suppliers depending on the type of market structure considered. To achieve this goal, we build a structural model and solve it by using game-theoretic and optimization approaches, in order to consider the different types of market structure, namely oligopoly (simplified to a duopoly in this case), and the two extremes of the competition spectrum, i.e., monopoly and perfect competition. We show that higher levels of investment in new electricity generation capacity are reached with decreasing probability of nuclear license extension and/or with higher levels of competition in the market. Moreover, investments in perfectly competitive markets are less influenced by changes in the probability of future nuclear license extension, resulting in a more stable long-term investment climate. However, the consideration of possible changes in market structure and gradual nuclear phase-out is crucial in order to not overestimate investment potential in Belgium.

Lightening the load: quantifying the potential for energy-efficient lighting to reduce peaks in electricity demand

One of the key challenges to greater renewable electricity supplies is the temporal mismatch between non-dispatchable renewable sources and peaks in electricity demand. In addition, increased electrification coupled with the de-carbonisation of electricity generation is likely to increase the scale of demand peaks. This could force investment in carbon-intensive peaker generation or capital intensive storage capacity as well as additional transmission and distribution network capacity which may then be substantially underutilised. Whilst considerable effort has been devoted to testing a range of demand response interventions to reduce or shift consumption, less attention has been given to the ability of certain appliances to permanently reduce demand at peak through energy efficiency. In this paper, we use a published model of future energy-efficient lighting uptake together with multi-year measured lighting demand data from a sample of residential households to model the potential power (MW) and energy (MWh) reductions of a ‘business as usual’ rate of efficient lighting adoption. Our estimates suggest that whilst lighting comprises ~ 4% of overall New Zealand annual electricity consumption, it comprises up to 12% of evening peak electricity consumption in winter. As a result, we estimate that by 2029, more efficient residential lighting could reduce New Zealand’s total annual demand by 1 TWh and reduce the highest winter evening peaks (at 17:00) by at least 500 MW (9%). The winter evening demand reduction would be roughly equivalent to avoiding the need for additional generation capacity of the scale of New Zealand’s Huntly Power Stations 1–4 (coal/gas) plus the Stratford peaker plant (gas open-cycle) and has clear implications for any electricity system that is intending to transition towards ~ 100% renewable generation at least cost.