Investment In Generation Capacity Research Articles

Estimating the willingness to pay for reliable electricity supply: A choice experiment study

This research examines households' willingness to pay (WTP) for an improved electricity service. Households' stated WTP is estimated using the choice experiment (CE) method. The data used in the estimations come from 350 in-person interviews conducted during the period 5–22 August 2008 in North Cyprus. Compensating variation (CV) estimates for a zero-outage scenario are calculated using the parameter estimates from the mixed logit (ML) model; these are 6.65 YTL (Turkish lira) per month (3.02 USD) for summer and 25.83 YTL per month (11.74 USD) for winter. In order to avoid the cost of outages, households are willing to incur a 3.6% and a 13.9% increase in their monthly electricity bill for summer and winter, respectively. The WTP per hour unserved is 0.28 YTL (0.13 USD) for summer, and 1.08 YTL (0.49 USD) for winter. A preliminary cost–benefit analysis indicates that the annualized economic benefits are approximately 42.7 million YTL (19.4 million USD) for the residential sector. This would justify an investment in additional generation capacity of approximately 268MW, which is far more than that which is needed to eliminate the service reliability problem.

Transmission and generation investment in electricity markets: The effects of market splitting and network fee regimes

We propose an equilibrium model that allows to analyze the long-run impact of the electricity market design on transmission line expansion by the regulator and investment in generation capacity by private firms in liberalized electricity markets. The model incorporates investment decisions of the transmission system operator and private firms in expectation of an energy-only market and cost-based redispatch. In different specifications we consider the cases of one vs. multiple price zones (market splitting) and analyze different approaches to recover network cost—in particular lump sum, generation capacity based, and energy based fees. In order to compare the outcomes of our multilevel market model with a first best benchmark, we also solve the corresponding integrated planner problem. Using two test networks we illustrate that energy-only markets can lead to suboptimal locational decisions for generation capacity and thus imply excessive network expansion. Market splitting heals these problems only partially. These results are valid for all considered types of network tariffs, although investment slightly differs across those regimes.

The effectiveness of a strategic reserve in the presence of a high portfolio share of renewable energy sources

To ensure sufficient investment in electricity generation capacity, mechanisms such as strategic reserves are being considered or already implemented. We analyze the effectiveness of a strategic reserve in the presence of a growing portfolio share of renewable energy sources (RES) with EMLab-Generation, an agent-based electricity market model. A strategic reserve can stabilize investment, but within limits. Uncertainty regarding future demand may cause the market to become instable, potentially leading to periods with very high electricity prices. In the presence of a large share of variable renewable energy sources, the reserve design should be adjusted or replaced by an alternative capacity mechanism.

Business case uncertainty of power plants in future energy systems with wind power

The European power sector is transforming due to climate policies and an increased deployment of intermittent RES. The sector will require thermal power plants for the decades to come, but their business cases are (negatively) affected by this transformation. This study presents a novel tool to quantify the effect of policy, price and project-related uncertainties on power plant business cases. This tool can support policymakers in stimulating necessary investments in new thermal generation capacity. We find that these investments are currently unsound (power plants recoup on average –12% to 59% of their initial investment). Future climate policy, i.e. the CO2 price, has a very strong impact on business cases (affects the profitability by 5–40%-points). The impact of the deployment of wind power is average (2–8%-point difference between 10% and 21% wind penetration). Variations in annual wind power production barely affect the profitability (variation of ±1%-point). To stimulate new investments, policymakers should first decrease the uncertainty in business cases caused by policy. Durable climate policy is especially important. Also, policies to increase the profits of thermal power plants should be carefully considered and implemented. This combined approach will reduce the revenue gap that needs to be bridged by supportive policies.

Market Signals and Investment in Variable Renewables

This paper examines theoretically how price signals affect investment in renewables. While feed-in tariffs (FIT) remunerate renewables with a constant subsidy independently from the market price, feed-in premia (FIP) support them with a subsidy on top of the electricity spot price. Under FIT, a strategic investor who also owns thermal generation favors renewables whose output is more variable, less correlated with demand and more correlated with the output of the system’s renewable feed-in, therefore increasing the variability of the system’s net demand, defined as demand net of renewable output. Consequently, this can result in an increase in the costs of integrating renewables in the system. In contrast, FIP leads to investment choices that can reduce integration costs. Furthermore, for a given set of renewable plants in a competitive market, the socially optimal investment in renewable generation capacity can be implemented by a FIP scheme where the subsidy is set at the level that leads firms to internalize the externalities of renewable energy.

Generation Investment and Resource Adequacy in Electricity Markets

This paper presents an overview of the issue of resource adequacy in general, and the specific problems presented by restructured markets for ensuring adequate investment in generation capacity. The theory of investment in ideal markets is contrasted with the actual behavior of investors in US markets in the past, and the potential for investment cycles in the future. The US experience with capacity markets, energy only markets and mandated reserve margins is summarized and contrasted. Theoretical models of markets, and consultant models that are based on the assumptions of economic theory, cannot be relied upon to provide reliable recommendations for effective policy decisions. The lack of high quality and impartial empirical work that would allow valid comparisons of the efficiency and effectiveness of different markets leaves regulators in the dark when choosing between resource adequacy mechanisms.

Generation Capacity Investments in Electricity Markets: Perfect Competition

Abstract: In competitive electricity markets, markets designs based on power exchanges where supply bidding (barring demand-side bidding) is at the sole short run marginal cost may not guarantee resource adequacy. As alternative ways to remedy the resource adequacy problem, we focus on three different market designs in detail when demand is inelastic, namely an energy-only market with VOLL pricing (or a price cap), an additional capacity market, and operating-reserve pricing. We also discuss demand-side bidding (i.e., a price responsive demand) which can be seen as a categorically different alternative to remedy the resource adequacy problem. We consider a perfectly competitive market consisting of three types of agents: generators, a transmission system operator, and consumers; all agents are assumed to have no market power. For each market design, we model and analyze capacity investment choices of firms using a two-stage game where generation capacities are installed in the first stage and generation takes place in future spot markets at the second stage. When future spot market conditions are assumed to be known a priori (i.e., deterministic demand case), we show that all of these two-stage models with different market mechanisms, except operating-reserve pricing, can be cast as single optimization problems. When future spot market conditions are not known in advance (i.e., under demand uncertainty), we essentially have a two-stage stochastic game. Interestingly, an equilibrium point of this stochastic game can be found by solving a two-stage stochastic program, in case of all of the market mechanisms except operating-reserve pricing. In case of operatingreserve pricing, while the formulation of an equivalent deterministic or stochastic optimization problem is possible when operating-reserves are based on observed demand, this simplicity is lost when operatingreserves are based on installed capacities. We generalize these results for other uncertain parameters in spot markets such as fuel costs and transmission capacities. Finally, we illustrate how all these models can be numerically tackled and present numerical experiments. In our numerical experiments, we observe that uncertainty of demand leads to higher total generation capacity expansion and a broader mix of technologies compared to the investment decisions assuming average demand levels. Furthermore for the same VOLL (or price cap) level and under the assumptions of random demand with finite support and no forced outages, energy-onlymarkets with VOLL pricing tend to lead to total generation capacity below the peak load with a certain probability whereas energy markets with a forward capacity market or operating-reserve pricing result in higher investments. Finally, the regulator decisions (e.g., reserve capacity target) in capacity markets and operating-reserve pricing can be chosen in such a way that results in very similar investment levels and fuel mix of generation capacities in b

Strategic Investment in Renewable Energy Sources: The Effect of Supply Intermittency

To analyze incentives for investing in the capacity to generate renewable electricity, we model the trade-off between renewable (e.g. wind) and nonrenewable (e.g. natural gas) technology. Renewable technology has a higher investment cost and yields only an intermittent supply of electricity; nonrenewable technology is reliable and has lower investment cost but entails both fuel expenditures and carbon emission costs. With reference to existing electricity markets, we model several interrelated contexts|the vertically integrated electricity supplier, market competition, and partial market competition with long-term fixed-price contracts for renewable electricity|and examine the effect of carbon taxes on the cost and share of wind capacity in an energy portfolio. We find that the intermittency of renewable technologies drives the effectiveness of carbon pricing mechanisms, which suggests that charging more for emissions could unexpectedly discourage investment in renewables. We also show that market liberalization may reduce investment in renewable capacity while increasing the overall system's cost and emissions. Fixed-price contracts with renewable generators can mitigate these detrimental effects, but not without possibly creating other problems. In short: actions to reduce the intermittency of renewable sources may be more effective than carbon taxes alone at promoting investment in renewable generation capacity.

Influence of Distributed Generation on Distribution Networks During Faults

Distributed generation is playing an increasingly important and positive role in decreasing network losses, reducing electricity prices, maintaining environmental and economical benefits, reducing the investment in generation capacity, and delaying the upgrade of the transmission system. Therefore, researchers have become interested with distributed generation and its connection with the main power network. But before connecting these resources with the main grid on the low-voltage level, the worst-case scenario that could occur must be analyzed first. This article introduces a procedure to study the effect of the distributed generation units on distribution systems during short-circuit periods. This effect is measured in terms of fault current, transient time, voltage total harmonic distortion, voltage sag, and voltage swell. The main objective of this study is to study the influence of distributed generation on distribution systems so the maximum distributed generation penetration that can be adopted in a distribution system without degrading the system performance is determined. A general purpose alternative transients program version of the electromagnetic transient program is used to accomplish the above goals. The proposed method is tested on IEEE 13-node test feeder distribution system to demonstrate its performance.

Operational flexibility and economics of power plants in future low-carbon power systems

Abstract Future power systems will require large shares of low-carbon generators such as renewables and power plants with Carbon Capture and Storage (CCS) to keep global warming below 2 °C. Intermittent renewables increase the system-wide demand for flexibility and affect the operation of thermal power plants. We investigate the operation of future power plants by first composing a comprehensive overview of the operational flexibility of current and future power plants. Next, a combined long-term optimization and hourly simulation is performed with the soft-linked MARKAL-NL-UU and REPOWERS models for The Netherlands in 2030 and 2050. We quantify and compare the technical and economic performance of power plants for four distinctly different future scenarios. We find that future low-carbon power systems will have large shares of intermittent renewable sources (19–42%) and also a 2–38% higher variability in residual load compared to the Baseline scenario. Hence, power plant operation will be more variable, which reduces their efficiency by 0.6–1.6% compared to the full-load efficiency. Enough flexibility is present in future power systems to accommodate renewables, due to advances in power plant flexibility and interconnectors. As a result, generators with CCS have a large market share (23–64% of power generated). Moreover, the current energy-based market model generates insufficient revenues: the price received per MWh covers only 84% (±30%) of the total generation costs per MWh of 77 €/MWh (±12€). This will discourage new investments in generation capacity and reduce power system adequacy. New or additional market designs may be required to ensure system adequacy in future power systems.

Generation Capacity Expansion Planning Under Hydro Uncertainty Using Stochastic Mixed Integer Programming and Scenario Reduction

Generation capacity expansion planning (GCEP) is the process of deciding on a set of optimal new investments in generation capacity to adequately supply future loads, while satisfying technical and reliability constraints. This paper shows the application of stochastic mixed-integer programming (SMIP) to account for hydrological uncertainty in GCEP for the Chilean Central Interconnected System, using a two-stage SMIP multi-period model with investments and optimal power flow (OPF). The substantial computational challenges posed by GCEP imply compromising between the detail of the stochastic hydrological variables and the detail of the OPF. We selected a subset of hydrological scenarios to represent the historical hydro variability using moment-based scenario reduction techniques. The tradeoff between modeling accuracy and computational complexity was explored both regarding the simplification of the MIP problem and the differences in the variables of interest. Using a simplified OPF model, we found the difference of using a subset of hydro scenarios to be small when compared with using a full representation of the stochastic variable. Overall, SMIP with scenario reduction provided optimal capacity expansion plans whose investment plus expected operational costs were between 1.3% and 1.9% cheaper than using a deterministic approach and proved to be more robust to hydro variability.

Security of Supply in European Electricity Markets—Determinants of Investment Decisions and the European Energy Union

The European Union and its Member States are seeking to decarbonize their energy systems, including the electricity sector and, at the same time, pursue market integration. However, renewable energy (RE) deployment and the liberalization of the energy-only market have raised concerns at the national level about the security of electricity supplies in the future. Some actors consider the lack of sufficient investments in generation capacities a threat to supply security. As a consequence, it was proposed that capacity markets solve these problems. The underlying assumption is that the market design is the only determining factor for investments in security of supply options. In this article, we question this narrow view and identify further determinants of the investment decisions of electricity market participants. Based on the insights of institutional sociology and economics, we understand the market to be a social institution that structures the behavioural expectations of market participants. Derived from the theoretical conceptualization and based on qualitative literature review and own work, we find four determinants for investment behaviour beyond the formal market design: Material opportunities, strategic actor behavior and identity, focusing events and discursive expectations about the future. With this perspective, we discuss the introduction of a European Energy Union as a possible tool that might have a great impact on the more informal determinants such as expectations about the future and the construction of a European energy narrative.

Lowering Saudi Arabia's fuel consumption and energy system costs without increasing end consumer prices

Using a multi-sector equilibrium model of the Saudi energy system that handles administered prices in a mixed-complementarity formulation, we present results from a set of policy scenarios that lower oil consumption in the country. Some of these scenarios are the solutions to Mathematical Programs subject to Equilibrium Constraints (MPECs) that maximize the net economic gain for the Saudi economy. The policies examined have the potential to generate economic gains exceeding 23 billion USD in 2011, or about 4% of Saudi Arabia's GDP. This economic gain comes mainly from inter-sectoral fuel pricing policies that incent shifting the mix in technologies that generate electricity and produce water from energy intensive technologies to more efficient ones. We show that when complemented by credits for investments in solar and nuclear power generation capacities, a modest increase in the transfer prices of fuels among sectors is sufficient to produce economic gains close to those achieved by deregulating transfer prices. The approach we develop here is an alternative to the classic recommendation of deregulating inter-sectoral fuel prices in situations where the conditions for successful liberalized markets do not exist. It is a template for introducing the notions of incentivizing behavior using prices into countries that rely more on administrative procedures than markets, leading to a deeper understanding of how markets can lead to economic gain.

Lowering Saudi Arabia's Fuel Consumption and Energy System Costs Without Increasing End Consumer Prices

Using a multi-sector equilibrium model of the Saudi energy system that handles administered prices in a mixed-complementarity formulation, we present results from a set of policy scenarios where end consumer prices are not altered. Some of these scenarios are the solutions to Mathematical Programs subject to Equilibrium Constraints (MPEC’s) that maximize the net economic gain for the Saudi economy. The policies examined would have potentially generated economic gains exceeding 23 billion USD in 2011, or about 4% of Saudi Arabia’s GDP. This economic gain comes mainly from inter-sectoral fuel pricing policies that incent shifting the mix in technologies that generate electricity and produce water. We show that when complemented by credits for investments in solar and nuclear power generation capacities, a modest increase in the transfer prices of fuels among sectors is sufficient to produce economic gains close to those achieved by deregulating transfer prices. The approach we develop here is an alternative to the classic recommendation of deregulating inter-sectoral fuel prices in situations where the conditions for successful liberalized markets do not exist.

An Econometric Analysis of Support Scheme Effects on Renewable Energy Investments in Europe

Support schemes for renewable electricity generation (RES-E) have been extensively applied the last decades. European countries have implemented both feed-in tariffs (FITs), renewable portfolio standards (RPS) and tendering schemes for different RES-E technologies. This paper examines the impact of these policies in the five largest electricity consuming countries in Europe using detailed data spanning 1990-2012. Following recent policy impact studies we employ the investment decision model specified by [1] where the share of return on an investment in renewable generation capacity that can be attributed to feed-in tariffs is isolated. Renewable portfolio standards and tendering schemes are also included in the econometric specification. Due to high FIT levels and reduced costs we find that investments in PV and onshore wind power have generally had a high expected return the last years. We conclude that FIT has significantly affected the development of PV and onshore wind in the five countries analyzed in the period 1990-2012. The significance of FIT on onshore wind generation contradicts previous findings. Also, it is confirmed that RPS has significantly positive effect on the development of bioenergy for power generation and that the presence of tendering schemes has contributed to the increase of onshore wind power.

Risk Assessment of Investments in Energy-only and Capacity Markets

This paper addresses the long term challenges of electricity markets. First, the economic theory of the missing money problem is outlined. Additionally, a risk assessment of different market designs is pursued. Finally, we will conclude that both market and regulatory risks are important issues of the discussion. Due to the relatively high complexity of capacity markets it can be expected that there will be changes to the market design and to relevant parameters - in particular shortly after the first implementation of such mechanisms. This might increase the uncertainty perceived by investors. However, if the period of validity is long enough, i.e. the investors can calculate with a relatively stable revenue stream, a capacity market might be an instrument for reducing the risks perceived by investors and hence for facilitating the financing of investments in new energy generation capacity.

Market Driven Power Plant Investment Perspectives in Europe: Climate Policy and Technology Scenarios until 2050 in the Model EMELIE-ESY

EMELIE-ESY is a partial equilibrium model with focus on electricity markets. Private investors optimize their generation capacity investment and dispatch over the horizon 2010 to 2050. In the framework of the Energy Modeling Forum 28, we investigate how climate policy regimes affect market developments under different technology availabilities and climate policies on the European power markets. The model projects an only minor increase of power consumption because of higher wholesale prices or energy efficiency current climate policy, and a balanced consumption pathway under ambitious climate policy. These results contrast with findings of POLES and PRIMES models in the reference case that predict unexpected heavy consumption increases by 2050. By contrast, we find no investment into Carbon Capture and Storage (CCS) and a diminishing share of nuclear energy. We find that renewable energy supply extension as projected can sufficiently meet electricity consumption complemented by only few capacity investments in conventional technology.

Impact of Demand Response on Thermal Generation Investment With High Wind Penetration

We present a stochastic programming model for investments in thermal generation capacity to study the impact of demand response (DR) at high wind penetration levels. The investment model combines continuous operational constraints and wind scenarios to represent the implications of wind variability and uncertainty at the operational level. DR is represented in terms of linear price-responsive demand functions. A numerical case study based on load and wind profiles of Illinois is constructed with 20 candidate generating units of various types. Numerical results show the impact of DR on both investment and operational decisions. We also propose a model in which DR provides operating reserves and discuss its impact on lowering the total capacity needed in the system. We observe that a relatively small amount of DR capacity is sufficient to enhance the system reliability. When compared to the case with no DR, a modest level of DR results in less wind curtailment and better satisfaction of reserve requirements, as well as improvements in both the social surplus and generator utilization, as measured by capacity factors.

The Power Generation Capacity Investment Model Basing on the Newton KKT Interior-point Method under the Market Environment of Low Carbon

Under the market environment of low carbon, whether renewable energy can obtain the power for sustainable development, promote the goal of the whole society and make money for investors depends on the rational optimization of power investment capacity and achieving power generation resources coordinated scheduling. This study constructs an expansion model of the generation capacity investment taking oligopoly, policy tools, carbon emissions trading right and green certificate system into account and uses the case analysis of the impact of ETS mechanism and the Tradable Green Certificate mechanism on power generation enterprises investment capacity with Newton KKT interior-point method. This study can also provide a strong decision basis for policy making.

MARKET DRIVEN POWER PLANT INVESTMENT PERSPECTIVES IN EUROPE: CLIMATE POLICY AND TECHNOLOGY SCENARIOS UNTIL 2050 IN THE MODEL EMELIE-ESY

In the framework of the Energy Modeling Forum 28, we investigate how climate policy regimes affect market developments under different technology availabilities on the European power markets. We use the partial equilibrium model EMELIE-ESY with focus on electricity markets in order to determine how private investors optimize their generation capacity investment and operation over the horizon 2010 to 2050. For the year 2050, the model projects a minor increase of power consumption of 10% under current climate policy, and a balanced pathway for consumption under ambitious climate policy compared to 2010 levels. These results contrast with findings of POLES and PRIMES models that predict strong consumption increases of 44% to 48% by 2050 and claim competitiveness of nuclear power and CCS options. Under ambitious climate policy, our findings correspond with major increases of wholesale electricity market prices and comparatively less pronounced emission price increases, which trigger no investments into Carbon Capture and Storage (CCS) and a strongly diminishing share of nuclear energy.