Climate Policy and Strategic Operations in a Hydro-Thermal Power System

2023. Farzad Hassanzadeh Moghimi (et al.). Energy Journal 44 (5), 47-74

Artikel

Decarbonisation of the Nordic power sector entails substantial variable renewable energy (VRE) adoption. While Nordic hydropower reservoirs can mitigate VRE output's intermittency, strategic hydro producers may leverage increased flexibility requirements to exert market power. Using a Nash-Cournot model, we find that even the current Nordic power system could yield modest gains from strategic reservoir operations regardless of a prohibition on "spilling" water to increase prices. Instead, strategic hydro producers could shift generation from peak to off-peak seasons. Such temporal arbitrage becomes more attractive under a climate package with a â‚¬100/t CO2 price and doubled VRE capacity. Since the package increases generation variability, lowers average prices, and makes fossil-fuelled plants unprofitable, strategic hydro producers face lower opportunity costs in shifting output from peak to off-peak seasons and encounter muted responses from price-taking fossil-fuelled plants. Hence, a climate package that curtails CO2 emissions may also bolster strategic hydro producers' leverage.

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Aggregator-Enabled Prosumers' Impact on Strategic Hydro-Thermal Operations

2023. Farzad Hassanzadeh Moghimi, Yihsu Chen, Afzal S. Siddiqui. Proceedings of the Annual Hawaii International Conference on System Sciences, 2693-2702

Konferens

Climate packages envisage decarbonization of the power system and electrification of the wider economy via variable renewable energy (VRE). These trends facilitate the rise of aggregator-enabled prosumers and engender demand for flexibility. By exploiting conducive geography, e.g., in the Nordic region, hydro reservoirs can mitigate VRE's intermittency. Nevertheless, hydro producers may leverage this increased need for flexibility to exert market power through temporal arbitrage. Using a Nash-Cournot model, we examine how aggregator-enabled prosumers with endogenous loads and VRE capacity interact with other agents to affect market outcomes. Based on Nordic data, we find that hydro producers enhance their market power by shifting their production away from periods in which prosumers are net buyers and "dumping" their output during periods in which prosumers are net sellers. Hence, jurisdictions that rely upon (hydro) storage to integrate VRE from prosumers will need to be wary of incumbent firms' incentives to manipulate prices.

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Transmission Investment under Uncertainty: Reconciling Private and Public Incentives

2022. Maria Lavrutich, Verena Hagspiel, Afzal S. Siddiqui. European Journal of Operational Research

Artikel

Private companies (PCs) in restructured electricity industries determine facility investment timing and sizing. Such decisions maximize the PC’s expected profit (rather than social welfare) under uncertainty. By anticipating the PC’s incentives, a welfare-maximizing transmission system operator (TSO) shapes the network to align public and private objectives. Via an option-based approach, we first quantify welfare losses from the PC’s and TSO’s conflicting objectives. We show that by anticipating the optimal timing and capacity decisions of the profit-maximizing PC, the TSO is able to reduce, though not eliminate, welfare loss. Next, we exploit the dependence of the PC’s capacity on the TSO’s infrastructure design to devise a proactive transmission-investment strategy. Hence, we mitigate welfare losses arising from misaligned incentives even in relatively uncertain markets.

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Operational planning of distributed energy generation for a semiconductor fabrication plant: [Operative Planung dezentralisierter Energieerzeugung für eine Halbleiterproduktionsanlage]

2022. Tobias F. Poemsl, Afzal S. Siddiqui. e & i Elektrotechnik und Informationstechnik

Artikel

The semiconductor industry is well known for its high resource consumption due to its clean room usage and power-intensive manufacturing technology. This is a significant financial burden for semiconductor fabrication plant owners who wish to minimize the cost needed to cover the electricity and gas loads for their daily operations. From a historical perspective, those electricity and gas cost reductions have been enabled by more energy-efficient manufacturing technologies. Due to the complexity of factors influencing the energy system of a semiconductor plant, other aspects have often been neglected and also not been studied intensively in the academic literature so far. One possibility for reducing energy costs is the integration of a microgrid as on-site distributed energy resources (DER) may offer a less cost-intensive way to supply the energy needed. Therefore, this paper seeks to answer the following research question: How much expected cost can be saved and risk mitigated at a semiconductor fabrication plant via DER? More precisely, in this paper, a microgrid at a semiconductor fabrication plant that has installed DER with combined heat and power (CHP) applications and demand response (DR) is used to simulate the expected annual energy costs under given uncertain electricity and gas prices at different installed capacity levels. A simulation-based approach is used to evaluate several DER capacity sizes. The results of the simulation show that installations of DER at a semiconductor microgrid can dominate the base case of doing nothing, considering the expected minimized cost, the expected CO2 emissions, and conditional value-at-risk (CVaR). In fact, DER can reduce the expected annual energy bill by up to 6%, whereas annual expected CO2 emissions can even be reduced by up to 22%. Moreover, with DER, a microgrid’s risk is reduced as it can react to market conditions and local demand. Additionally, the true potential of microgrid cost savings can only be enabled when DR is allowed and proves particularly effective when energy prices are more volatile.

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Ambiguities and nonmonotonicities under prosumer power. Optimal distributed energy resource investment in a deregulated electricity industry

2022. Afzal S. Siddiqui, Sauleh A. Siddiqui. TOP - An Official Journal of the Spanish Society of Statistics and Operations Research

Artikel

Prosumers adopt distributed energy resources (DER) to cover part of their own consumption and to sell surplus energy. Although individual prosumers are too dispersed to exert operational market power, they may collectively hold a strategic advantage over conventional generation in selecting DER capacity via aggregators. We devise a bilevel model to examine DER capacity sizing by a collective prosumer as a Stackelberg leader in an electricity industry where conventional generation may exert market power in operations. At the upper level, the prosumer chooses DER capacity in anticipation of lower-level operations by conventional generation and DER output. We demonstrate that exertion of market power in operations by conventional generation and the marginal cost of conventional generation affect DER investment by the prosumer in a nonmonotonic manner. Intuitively, in an industry where conventional generation exerts market power in operations similar to a monopoly (MO), the prosumer invests in more DER capacity than under perfectly competitive operations (PC) to take advantage of a high market-clearing price. However, if the marginal cost of conventional generation is high enough, then this intuitive result is reversed as the prosumer adopts more DER capacity under PC than under MO. This is because the high marginal cost of conventional generation prevents the market-clearing price from decreasing, thereby allowing for higher prosumer revenues. Moreover, competition relieves the chokehold on consumption under MO, which further incentivises the prosumer to expand DER capacity to capture market share. We prove the existence of a critical threshold for the marginal cost of conventional generation that leads to this counterintuitive result. Finally, we propose a countervailing regulatory mechanism that yields welfare-enhancing DER investment even in deregulated electricity industries.

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Economics of Power Systems

2022. Makoto Tanaka, Antonio J. Conejo, Afzal S. Siddiqui.

Bok

This book describes the latest microeconomic concepts and operations research (OR) techniques needed to comprehend the design and operation of power markets, as well as the actions of their agents: producers, consumers, operators, and regulators. This is critical when it comes to addressing a constantly evolving power system environment that incorporates an increasing number of no-marginal-cost renewable sources, increasingly competitive storage facilities, increasingly responsive demands, and widespread communication channels that allow distributed decision-making. Such evolving environments call for a re-examination of the microeconomic concepts and OR techniques required by graduate students and practitioners in the electric energy field.

This accessible, tutorial-style book features numerous illustrative examples to help readers grasp the economic concepts and OR procedures used by power market professionals. The authors explain these concepts and procedures and present a vision of a renewable-dominated marketplace. Each chapter also includes exercises.

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Strategic storage use in a hydro-thermal power system with carbon constraints

2021. Sebastien Debia, Pierre-Olivier Pineau, Afzal S. Siddiqui. Energy Economics 98

Artikel

Several interconnected power systems worldwide have largely thermal and hydro production along with CO2 cap-and-trade (C&T) systems and variable renewable energy sources (VRES). C&T policies increase VRES generation, and socially optimal storage deployment could integrate VRES output. However, hydro reservoirs may be used strategically due to market power. We investigate these distortions and assess measures for their mitigation via a bottom-up equilibrium model of New York and Quebec. In particular, we find evidence that hydro producers shift water between seasons to manipulate electricity prices even under a net-hydro production constraint. Alternative regulation covering net imports as well as net-hydro production limits such temporal arbitrage but enables firms with both thermal generation and pumped-hydro storage to exercise spatial arbitrage. We demonstrate that these distortions will be exacerbated under more stringent C&T policies because price-taking thermal producers are less able to respond to price signals.

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Economic and Environmental Consequences of Market Power in the South-East Europe Regional Electricity Market

2021. Verena Viskovic (et al.). Energy Journal 42 (6), 145-170

Artikel

Market power in electricity and emission-permit markets in the South-East Europe Regional Electricity Market, which comprises both EU members subject to the EU Emissions Trading System (ETS) and non-EU members exempt from it, affects social welfare and carbon leakage. We examine its impact under three market settings: perfect competition (PC) and two leader-follower versions, in which a leader can exert market power in either the electricity market (S-T) or both the electricity and permit markets (S). Under PC, carbon leakage is equal to 11%-39% of ETS emission reduction depending on the cap stringency. Generally, in S-T, the leader's capacity withholding results in ETS emissions below and non-ETS emissions above PC levels. However, carbon leakage is lower vis-à-vis PC as the ETS emission reduction offsets the non-ETS emission increase. Finally, in S, the leader's propensity to lower the permit price increases ETS emissions and exacerbates carbon leakage compared to S-T.

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Regulatory jurisdiction and policy coordination

2020. Makoto Tanaka, Yihsu Chen, Afzal S. Siddiqui. Journal of the Operational Research Society

Artikel

This study discusses important aspects of policy modeling based on a leader-follower game of policymakers. We specifically investigate non-cooperation between policymakers and the jurisdictional scope of regulation via bi-level programming. Performance-based environmental policy under the Clean Power Plan in the United States is chosen for our analysis. We argue that the cooperation of policymakers is welfare enhancing. Somewhat counterintuitively, full coordination among policymakers renders performance-based environmental policy redundant. We also find that distinct state-by-state regulation yields higher social welfare than broader regional regulation. This is because power producers can participate in a single power market even under state-by-state environmental regulation and arbitrage away the CO2 price differences by adjusting their generation across states. Numerical examples implemented for a stylized test network illustrate the theoretical findings.

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Spatial and sectoral benefit distribution in water-energy system design

2020. Jose M. Gonzalez (et al.). Applied Energy 269

Artikel

The design of water and energy systems has traditionally been done independently or considering simplified interdependencies between the two systems. This potentially misses valuable synergies between them and does not consider in detail the distribution of benefits between different sectors or regions. This paper presents a framework to couple integrated water-power network simulators with multi-objective optimisation under uncertainty to explore the implications of explicitly including spatial topology and interdependencies in the design of multi-sector integrated systems. A synthetic case study that incorporates sectoral dependencies in resource allocation, operation of multi-purpose reservoirs and spatially distributed infrastructure selection in both systems is used. The importance of explicitly modelling the distribution of benefits across different sectors and regions is explored by comparing different spatially aggregated and disaggregated multi-objective optimisation formulations. The results show the disaggregated formulation identifies a diverse set of non-dominated portfolios that enables addressing the spatial and sectoral distribution of benefits, whilst the aggregated formulations arbitrarily induce unintended biases. The proposed disaggregated approach allows for detailed spatial design of interlinked water and energy systems considering their complex regional and sectoral trade-offs. The framework is intended to assist planners in real resource systems where diverse stakeholder groups are mindful of receiving their fair share of development benefits.

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Analysis of Environmental Policy in the Power Sector

2020. Yihsu Chen, Afzal Siddiqui, Makoto Tanaka.

Bok

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Strategic offering of a flexible producer in day-ahead and intraday power markets

2020. Tuomas Rintamäki, Afzal S. Siddiqui, Ahti Salo. European Journal of Operational Research 284 (3), 1136-1153

Artikel

The increase in intraday electricity market volumes due to intermittent renewable generation may give a strategic producer an opportunity to exert market power. We study offering strategies of a flexible producer in day-ahead and intraday markets using a bi-level model in which the upper level represents the profit-maximization problem of the producer and the lower-level problems clear the day-ahead and intraday markets sequentially. Using a three-node network, we first demonstrate that a flexible producer with perfect forecasts can increase its profit in both markets by coordinating its offer so as to cause transmission grid congestion or lack of competitive generation capacity. Moreover, we show that strategic behavior is possible even when the day-ahead and intraday markets are cleared simultaneously to lower balancing costs. We next assess these market designs in a Nordic test network and offer an explanation for high Nordic intraday prices. Finally, via an annual simulation using the Nordic market data, we verify that strategic offering in day-ahead and intraday markets under imperfect forecasts leads to increased profits vis-a-vis perfect competition but are mitigated through simultaneous market clearing.

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Utility-scale energy storage in an imperfectly competitive power sector

2020. Vilma Virasjoki (et al.). Energy Economics 88

Artikel

Interest in sustainabiity has increased the share of variable renewable energy sources (VRES) in power generation. Energy storage systems' potential to mitigate intermittencies from non-dispatchable VRES has enhanced their appeal. However, the impacts of storage vary based on the owner and market conditions. We examine the policy implications of investments in utility-scale battery storage via a bi-level optimization model. The lower level depicts power system operations, modeled as either perfect competition or Coumot oligopoly to allow for the assessment of producer market power. The upper-level investor is either a welfare-maximizer or a profit-maximizing standalone merchant to reflect either welfare enhancement or arbitrage, respectively. We implement a realistic case study for Western Europe based on all possible size-location storage investment combinations. We find that market competition affects investment sizes, locations, and their profitability more than the investor's objectives. A welfare-maximizer under perfect competition invests the most in storage capacity. Consumers typically gain most from storage investments in all cases, exceeding the gains for the investors. Specifically, our results show that storage investments may either not occur or be located differently than at social optimum, if market power is exerted. Thus, policy makers need to anticipate producer market power when setting regulation.

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Wasserstein-Distance-Based Temporal Clustering for Capacity-Expansion Planning in Power Systems

2020. Lucas Condeixa, Fabricio Oliveira, Afzal Siddiqui. 2020 International Conference on Smart Energy Systems and Technologies (SEST)

Konferens

As variable renewable energy sources are steadily incorporated in European power systems, the need for higher temporal resolution in capacity-expansion models also increases.Naturally, there exists a trade-off between the amount of temporal data used to plan power systems for decades ahead and time resolution needed to represent renewable energy variability accurately. We propose the use of the Wasserstein distance as a measure of cluster discrepancy using it to cluster demand, wind availability, and solar availability data. When compared to the Euclidean distance and the maximal distance, the hierarchical clustering performed using the Wasserstein distance leads to capacity-expansion planning that 1) more accurately estimates system costs and 2) more efficiently adopts storage resources. Numerical results indicate an improvement in cost estimation by up to 5% vis-à-vis the Euclidean distance and a reduction of storage investment that is equivalent to nearly 100% of the installed capacity under the benchmark full time resolution.

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A Review of Energy Storage System Legislation in the US and the European Union

2019. Diego A. Tejada-Arango (et al.).

Artikel

Purpose of Review

This paper focuses on the current possibilities for energy storage systems (ESS) to participate in different power system services. ESS can provide multiple services such as spinning reserve, deferral upgrades, and energy management. However, this versatility of ESS poses a challenge for regulators in designing markets where ESS have prominent roles. We assess recent regulatory proposals in the US and the EU in order to understand their implications for ESS.

Recent Findings

These proposals attempt to improve the current rules for efficient ESS deployment. Nevertheless, they have different approaches to the same problem. We discuss these differences in an attempt to shed light on the regulatory debate about ESS ownership and market design.

Summary

The successful integration of ESS will depend on proper incentives to provide multiple services without hampering the current market structure. New asset definitions could help to define the roles of ESS as either a generation or a transmission asset.

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Merchant Storage Investment in a Restructured Electricity Industry

2019. Afzal Siddiqui, Ramteen Sioshansi, Antonio J. Conejo. Energy Journal 40 (4), 129-163

Artikel

Restructuring and liberalisation of the electricity industry creates opportunities for investment in energy storage, which could be undertaken by a profit-maximising merchant storage operator. Because such a firm is concerned solely with maximising its own profit, the resulting storage-investment decision may be socially suboptimal (or detrimental). This paper develops a bi-level model of an imperfectly competitive electricity market. The modelling framework assumes electricity-generation and storage-operations decisions at the lower level and storage investment at the upper level. Our analytical results demonstrate that a relatively high (low) amount of market power in the generation sector leads to low (high) storage-capacity investment by the profit-maximising storage operator relative to a welfare maximiser. This can result in net social welfare losses with a profit-maximising storage operator compared to a no-storage case. Moreover, there are guaranteed to be net social welfare losses with a profit-maximising storage operator if the generation sector is sufficiently competitive. Using a charge on generation ramping between off- and on-peak periods, we induce the profit-maximising storage operator to invest in the same level of storage capacity as the welfare-maximising firm. Such a ramping charge can increase social welfare above the levels that are attained with a welfare-maximising storage operator.

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Opportunity cost including short-term energy storage in hydrothermal dispatch models using a linked representative periods approach

2019. Diego A. Tejada-Arango (et al.). Energy 188

Artikel

Short-term energy storage systems, e.g., batteries, are becoming one promising option to deal with flexibility requirements in power systems due to the accommodation of renewable energy sources. Previous works using medium- and long-term planning tools have modeled the interaction between short-term energy storage systems and seasonal storage (e.g., hydro reservoirs) but despite these developments, opportunity costs considering the impact of short-term energy storage systems in stochastic hydrothermal dispatch models have not been analyzed. This paper proposes a novel formulation to include short-term energy storage systems operational decisions in a stochastic hydrothermal dispatch model, which is based on a Linked Representative Periods approach. The Linked Representative Periods approach disposes of both intra- and inter-period storage constraints, which in turn allow to adequately represent both short- and long-term storage at the same time. Apart from the novelty of the model formulation itself, one of the main contributions of this research stems from the underlying economic information that can be extracted from the dual variables of the intra- and inter-period constraints, which allows to derive an hourly opportunity cost of storage. Such a detailed hourly economic value of storage has not been proposed before in the literature and is not possible in a classic Load Duration Curve model that does not adequately capture short-term operation. This advantage is reflected in the case study results. For instance, the model proposed in this paper and based on Linked Representative Periods obtains operating decisions of short-term energy storage systems with errors between 5% and 10%, while the classic Load Duration Curve approach fails by an error greater than 100%. Moreover, the Load Duration Curve model cannot determine opportunity costs on an hourly basis and underestimates these opportunity costs of hydro (also known as water value) by 6%–24% for seasonal hydro reservoirs. The proposed Linked Representative Periods model produces an error on the opportunity cost of hydro units lower than 3%. Hourly opportunity costs for short-term battery energy storage systems using dual variables from both intra- and inter-period storage balance equations in the proposed model are also presented and analyzed. The case study shows that the proposed approach successfully internalizes both short- and long-term opportunity costs of energy storage systems. These results are useful for planning and policy analysis, as well as for bidding strategies of ESS owners in day-ahead markets and not taking them into account may lead to infeasible operation or to suboptimal planning.

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Regional carbon policies in an interconnected power system

2019. Verena Višković (et al.). Energy Policy 134

Artikel

Interconnected regional electricity markets are often subject to asymmetric carbon policies with partial coverage for CO2 emissions. While the resulting problem of carbon leakage has been well studied, its mitigation has received relatively less attention. We devise a proactive carbon policy via a bi-level modelling approach by considering the impact of an emission cap that limits the cost of damage from a regional power market. In particular, a welfare-maximising policymaker sets the cap when facing profit-maximising producers and the damage costs from their emissions at two nodes. A partial-coverage policy could degrade maximised social welfare and increase total regional CO2 emissions with potential for carbon leakage due to a higher nodal price difference. A modified carbon policy that considers CO2 emissions from both nodes tightens the cap, which increases maximised social welfare and decreases total CO2 emissions vis-a-vis the partial-coverage policy, albeit at the cost of greater scope for carbon leakage as it causes nodal prices to diverge. As a compromise, an import-coverage policy, implemented by California, that counts only domestic and imported CO2 emissions could alleviate carbon leakage at the cost of lower maximised social welfare with higher total emissions vis-a-vis the modified-coverage policy.

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Strategic use of storage

2019. Sébastien Debia, Pierre-Olivier Pineau, Afzal S. Siddiqui. Energy Economics 80, 100-122

Artikel

Concerns about climate change have spurred governments to reduce carbon emissions by supporting adoption of renewable energy (RE) technologies. Due to the intermittent and location-specific nature of RE technologies, energy storage has become important because it could be used to smooth out temporal disparities in residual demand. Thus, carbon policy has made storage-enabled RE generation more critical to the power sector, and this enhanced position could be exploited by firms to exert market power. Using an equilibrium model, we examine the implications of policy interventions and technological change on the marginal value of energy storage in a power market with RE and thermal generation. In particular, we specify the market conditions under which RE producers with storage strategically shift deployment of their resource to the off-peak period and outline its implications for the marginal value of RE storage. Moreover, we find that even price-taking RE producers may actually increase off-peak RE production as storage efficiency increases. Consequently, the RE producer's profit decreases with storage efficiency, which conflicts with the social objective of improving storage efficiency. These private and social incentives can be better aligned via a carbon tax, however. Hence, our results may inform the regulatory process governing market design of a power sector with increasing capacities of RE generation and storage.

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Sustainable transmission planning in imperfectly competitive electricity industries

2019. Afzal S. Siddiqui, Makoto Tanaka, Yihsu Chen. European Journal of Operational Research 275 (1), 208-223

Artikel

We explore the role of a transmission system operator (TSO) that builds a transmission line to accommodate renewable energy in order to lower emissions as required by government policy. In contrast to central planning, a TSO in a deregulated electricity industry can only indirectly influence outcomes through its choice of the transmission line capacity. Via a bi-level model, we show that this results in less transmission capacity and with limited emissions control in a perfectly competitive industry vis-a-vis a benchmark centrally planned system. A carbon charge on industry that fully accounts for the cost of pollution damage leads to a perfect alignment of incentives and maximised social welfare only under perfect competition. By contrast, a carbon charge may actually lower social welfare under a Cournot oligopoly as the resulting reduction in consumption facilitates the further exercise of market power.

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Investing in Time-to-Build Projects With Uncertain Revenues and Costs

2018. Lauri Kauppinen, Afzal S. Siddiqui, Ahti Salo. IEEE transactions on engineering management 65 (3), 448-459

Artikel

Lagging public-sector investment in infrastructure and the deregulation of many industries mean that the private sector has to make decisions under multiple sources of uncertainty. We analyze such investment decisions by accounting for both multiple sources of uncertainty and the time-to-build aspect. The latter feature arises in the energy and transportation sectors, because investors can decide the rate at which the project is completed. Furthermore, two explicit sources of uncertainty represent the discounted cash inflows and outflows of the completed project. We use a finite-difference scheme to solve numerically the option value and the optimal investment threshold. Somewhat counterintuitively, with a relatively long time to build, a reduction in the growth rate of the discounted operating cost may actually lower the investment threshold. This is contrary to the outcome when the stepwise aspect is ignored in a model with uncertain price and cost. Hence, research and development efforts to enhance emerging technologies may be more relevant for infrastructure projects with long lead times.

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Market Power with Combined Heat and Power Production in the Nordic Energy System

2018. Vilma Virasjoki (et al.). IEEE Transactions on Power Systems 33 (5), 5263-5275

Artikel

The trend toward increasing energy efficiency and variable renewable energy (VRE) production has implications for combined heat and power (CHP) plants, which operate in both the price-driven power market and the district heating (DH) sector. Since CHP will be important in VRE integration, we develop a complementarity model to analyze CHP producers' roles in integrated markets. We use a Nordic case study to gain insights into (i) the effect of the link between CHP and DH on market power and (ii) market power's impact on operations in the DH sector. The results indicate that (i) the link of CHP to DH supply can increase market power and (ii) market power can induce shifts in DH production from heat-only to CHP.

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Market Power with Tradable Performance-Based CO₂ Emission Standards in the Electricity Sector

2018. Yihsu Chen, Makoto Tanaka, Afzal S. Siddiqui. Energy Journal 39 (6), 121-145

Artikel

The U.S. Clean Power Plan stipulates a state-specific performance-based CO2 emission standard, delegating states with considerable flexibility for using either a tradable performance-based or a mass-based permit program. This paper analyzes these two standards under imperfect competitive. We limit our attention to (1) short-run analyses and (2) a situation in which all states are subject to the same type of standard. We show that while the cross-subsidy inherent in the performance-based standard might effectively reduce power prices, it could also inflate energy consumption. A dominant firm with a relatively clean endowment under the performance-based standard would be able to manipulate the electricity market as well as to elevate permit prices, which might worsen market outcomes compared to its mass-based counterpart. On the other hand, the "cross-subsidy" could be the dominant force leading to a higher social welfare if the leader has a relatively dirty endowment.

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Policy implications of downscaling the time dimension in power system planning models to represent variability in renewable output

2018. Lina Reichenberg, Afzal S. Siddiqui, Sonja Wogrin. Energy 159, 870-877

Artikel

Due to computational constraints, power system planning models are typically unable to incorporate full annual temporal resolution. In order to represent the increased variability induced by large amounts of variable renewable energy sources, two methods are investigated to reduce the time dimension: the integral approach (using typical hours based on demand and renewable output) and the representative days method (using typical days to capture annual variability). These two approaches are tested with a benchmark implementation that incorporates full time representation in order identify their suitability for assessing power systems with high renewable penetration. The integral method predicts renewable capacities within a 10% error margin, this paper's main performance metric, using just 32 time steps, while the representative days approach needs 160–200 time steps before providing similarly accurate renewable capacity estimates. Since the integral method generally cannot handle variation management, such as trade and storage, without enhancing the state-space representation, it may be more applicable to one-node models, while the representative days method is suitable for multi-regional models. In order to assess power systems with increasing renewable policy targets, models should be designed to handle at least the 160 time steps needed to provide results that do not systematically overestimate the renewable capacity share.

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Bouncing Back

2017. Afzal S. Siddiqui, Ryuta Takashima. Proceedings of the 21st Annual International Real Options Conference

Konferens

Motivated by the need to bolster the resilience of infrastructure, such as bridges, nuclear power plants, and ports, in face of extreme weather events, we consider two types of projects: “riskier” and “safer.” Each type of project, once constructed, earns identical instantaneous cash flows and is subject to the same risk of outage, which causes its cash flows to diminish. The only difference between the two projects is that the repair rate of the “safer” project is greater than that of the “riskier” one. Naturally, the “safer” project is more valuable to an investor due to its greater resilience. However, how much extra would an investor be willing to pay for this resilience? Under which circumstances would it be reasonable to replace the outage and repair rates with average outage factors? Using a real options approach, we show that even though the proportions of up- and down-times remain fixed, changes in the transition rates affect the willingness to pay for resilience. This implies that use of average outage factors will incorrectly inflate the resilience premium. In fact, only in the limit when transitions occur at infinitely high rates does the use of average outage factors accurately reflect the investor’s willingness to pay for resilience. Somewhat paradoxically, very frequent transitions reflect a situation in which average outage factors may be used.

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Capacity optimization under uncertainty

2017. Hettie J. Boonman, Afzal S. Siddiqui. European Journal of Operational Research 262 (2), 660-672

Artikel

Time lags in switching operational modes are typical in the manufacturing and power sectors but are not treated in most real options models. In this paper, we consider a firm that has the opportunity to suspend and to resume production infinitely many times subject to a time lag after each startup decision. We contribute to the literature by allowing the firm to determine its level of installed capacity in conjunction with its optimal investment timing. We find that an increase in the length of the time lag results in an increase in the optimal capacity level. Capacity optimization also interacts with the length of the time lag to affect investment timing and the triggers to suspend and resume production, thereby weakening the result about hysteresis from a standard real options model. Under the assumption of a fixed level of capacity, a longer lag speeds up the decision to resume operations due to a positive upside to the revenue but delays the suspension of operations. By contrast, with capacity optimization, a longer time lag results in a larger capacity choice, which can indirectly delay the investment decision and the timing to resume operations. This indirect effect dominates when the level of market uncertainty is low and the time lag is initially small.

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Does renewable energy generation decrease the volatility of electricity prices? An analysis of Denmark and Germany

2017. Tuomas Rintamäki, Afzal S. Siddiqui, Ahti Salo. Energy Economics 62, 270-282

Artikel

Although variable renewable energy (VRE) technologies with zero marginal costs decrease electricity prices, the literature is inconclusive about how the resulting shift in the supply curves impacts price volatility. Because the flexibility to respond to high peak and low off-peak prices is crucial for demand-response applications and may compensate for the losses of conventional generators caused by lower average prices, there is a need to understand how the penetration of VRE affects volatility. In this paper, we build distributed lag models with Danish and German data to estimate the impact of VRE generation on electricity price volatility. We find that in Denmark wind power decreases the daily volatility of prices by flattening the hourly price profile, but in Germany it increases the volatility because it has a stronger impact on off-peak prices. Our analysis suggests that access to flexible generation capacity and wind power generation patterns contribute to these differing impacts. Meanwhile, solar power decreases price volatility in Germany. By contrast, the weekly volatility of prices increases in both areas due to the intermittency of VRE. Thus, policy measures for facilitating the integration of VRE should be tailored to such region-specific patterns.

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Implications of the EU Emissions Trading System for the South-East Europe Regional Electricity Market

2017. Verena Višković, Yihsu Chen, Afzal S. Siddiqui. Energy Economics 65, 251-261

Artikel

As part of its climate policy, the European Union (EU) aims to reduce greenhouse gas (GHG) emissions levels by 20% by the year 2020 compared to 1990 levels. Although the EU is projected to reach this goal, its achievement of objectives under its Emissions Trading System (ETS) may be delayed by carbon leakage, which is defined as a situation in which the reduction in emissions in the ETS region is partially offset by an increase in carbon emissions in the non-ETS regions. We study the interaction between emissions and hydropower availability in order to estimate the magnitude of carbon leakage in the South-East Europe Regional Electricity Market (SEE-REM) via a bottom-up partial equilibrium framework. We find that 6.3% to 40.5% of the emissions reduction achieved in the ETS part of SEE-REM could be leaked to the non-ETS part depending on the price of allowances. Somewhat surprisingly, greater hydropower availability may increase emissions in the ETS part of SEE-REM. However, carbon leakage might be limited by demand response to higher electricity prices in the non-ETS area of SEE-REM. Such carbon leakage can affect both the competitiveness of producers in ETS member countries on the periphery of the ETS and the achievement of EU targets for CO₂ emissions reduction. Meanwhile, higher non-ETS electricity prices imply that the current policy can have undesirable outcomes for consumers in non-ETS countries, while non-ETS producers would experience an increase in their profits due to higher power prices as well as exports. The presence of carbon leakage in SEE-REM suggests that current EU policy might become more effective when it is expanded to cover more countries in the future.

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Are Targets for Renewable Portfolio Standards Too Low? The Impact of Market Structure on Energy Policy

2016. Afzal S. Siddiqui, Makoto Tanaka, Yihsu Chen. European Journal of Operational Research 250 (1), 328-341

Artikel

In order to limit climate change from greenhouse gas emissions, governments have introduced renewable portfolio standards (RPS) to incentivise renewable energy production. While the response of industry to exogenous RPS targets has been addressed in the literature, setting RPS targets from a policymaker's perspective has remained an open question. Using a bi-level model, we prove that the optimal RPS target for a perfectly competitive electricity industry is higher than that for a benchmark centrally planned one. Allowing for market power by the non-renewable energy sector within a deregulated industry lowers the RPS target vis-a-vis perfect competition. Moreover, to our surprise, social welfare under perfect competition with RPS is lower than that when the non-renewable energy sector exercises market power. In effect, by subsidising renewable energy and taxing the non-renewable sector, RPS represents an economic distortion that over-compensates damage from emissions. Thus, perfect competition with RPS results in "too much" renewable energy output, whereas the market power of the non-renewable energy sector mitigates this distortion, albeit at the cost of lower consumer surplus and higher emissions. Hence, ignoring the interaction between RPS requirements and the market structure could lead to sub-optimal RPS targets and substantial welfare losses.

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Energy-efficient building retrofits

2016. Paula Rocha, Michal Kaut, Afzal S. Siddiqui. Energy 101, 278-287

Artikel

Improving energy efficiency in European Union buildings will require retrofitting much of the existing stock due to limited new construction opportunities. Given uncertainty in energy prices and technology costs stemming from deregulation, a stochastic optimisation framework is desirable for long-term decision support. We synthesise treatment of uncertainty and risk management to obtain insights about the impact of retrofits on energy consumption, costs, CO₂ emissions, and risk at real buildings in Austria and Spain. The optimal strategy for the Spanish site is to invest in photovoltaic and solar thermal technologies. This lowers expected costs by 8.5% and reduces expected primary energy consumption and CO₂ emissions by 20% relative to using existing equipment. By limiting exposure to volatile energy prices, the strategy also yields a nearly 10% reduction in risk. We obtain similar results also for the Austrian site. Via this framework, tradeoffs among competing objectives and the effectiveness of proposed regulation may be assessed. Specifically, we find that more stringent restrictions on energy efficiency are economically viable if regulation also facilitates enhanced operational decision support for buildings. Indeed, primary energy consumption can be lowered only through more on-site generation such as combined heat and power, which is more complex for building managers to deploy.

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How much is enough? Optimal support payments in a renewable-rich power system

2016. Tuomas Rintamäki, Afzal S. Siddiqui, Ahti Salo. Energy 117 (1), 300-313

Artikel

The large-scale deployment of intermittent renewable energy sources may cause substantial power imbalance. Together with the transmission grid congestion caused by the remoteness of these sources from load centers, this creates a need for fast-adjusting conventional capacity such as gas-fired plants. However, these plants have become unprofitable because of lower power prices due to the zero marginal costs of renewables. Consequently, policymakers are proposing new measures for mitigating balancing costs and securing supply. In this paper, we take the perspective of the regulator to assess the effectiveness of support payments to flexible generators. Using data on the German power system, we implement a bi-level programming model, which shows that such payments for gas-fired plants in southern Germany reduce balancing costs and can be used as part of policy to integrate renewable energy.

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Investment in Electricity Generation and Transmission

2016. Antonio J. Conejo (et al.).

Bok

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Market Impacts of Energy Storage in a Transmission-Constrained Power System

2016. Vilma Virasjoki (et al.). IEEE Transactions on Power Systems 31 (5), 4108-4117

Artikel

Environmental concerns have motivated governments in the European Union and elsewhere to set ambitious targets for generation from renewable energy (RE) technologies and to offer subsidies for their adoption along with priority grid access. However, because RE technologies like solar and wind power are intermittent, their penetration places greater strain on existing conventional power plants that need to ramp up more often. In turn, energy storage technologies, e.g., pumped hydro storage or compressed air storage, are proposed to offset the intermittency of RE technologies and to facilitate their integration into the grid. We assess the economic and environmental consequences of storage via a complementarity model of a stylized Western European power system with market power, representation of the transmission grid, and uncertainty in RE output. Although storage helps to reduce congestion and ramping costs, it may actually increase greenhouse gas emissions from conventional power plants in a perfectly competitive setting. Conversely, strategic use of storage by producers renders it less effective at curbing both congestion and ramping costs, while having no net overall impact on emissions.

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Optimal Operation of Combined Heat and Power under Uncertainty and Risk Aversion

2016. Lajos Maurovich-Horvat, Paula Rocha, Afzal S. Siddiqui. Energy and Buildings 110, 415-425

Artikel

Despite the proven benefits of combined heat and power (CHP) and recently introduced subsidies to support it, CHP adoption has not met its targets. One of the possible reasons for this is risk from uncertain electricity and gas prices. To gain insights into the risk management of a CHP unit, we develop a multi-stage stochastic mean-risk optimisation model for the medium-term management of a distributed generation system with a gas-fired microturbine with heat recovery and a boiler. The model adopts the perspective of a large consumer that procures gas (for on-site generation) and electricity (for consumption) on the spot and futures markets. The consumer's risk aversion is incorporated into the model through the conditional value-at-risk (CVaR) measure. We show that CHP not only decreases the consumer's expected cost and risk exposure by 10% each but also improves expected energy efficiency by 4 percentage points and decreases expected CO₂ emissions by 16%. The risk exposure can be further mitigated through the use of financial contracts.

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Optimal Selection of Distributed Energy Resources under Uncertainty and Risk Aversion

2016. Lajos Maurovich-Horvat (et al.). IEEE transactions on engineering management 63 (4), 462-474

Artikel

The adoption of small-scale electricity generation has been hindered by uncertain electricity and gas prices. In order to overcome this barrier to investment, we develop a mean-risk optimization model for the long-term risk management problem of an energy consumer using stochastic programming. The consumer can invest in a number of generation technologies, and also has access to electricity and gas futures to reduce its risk. We examine the role of on-site generation in the consumer's riskmanagement strategy, as well as interactions between on-site generation and financial hedges. Our study shows that by swapping electricity (with high price volatility) for gas (with low price volatility), even relatively inefficient technologies reduce risk exposure and CO2 emissions. The capability of on-site generation is enhanced through the use of combined heat and power (CHP) applications. In essence, by investing in a CHP unit, a consumer obtains the option to use on-site generation whenever the electricity price peaks, thereby reducing its financial risk. Finally, in contrast to the extant literature, we demonstrate that on-site generation affects the consumer's decision to purchase financial hedges. In particular, while on-site generation and electricity futures may act as substitutes, on-site generation and gas futures can function as complements.

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The natural hedge of a gas-fired power plant

2016. Xiaojia Guo, Alexandros Beskos, Afzal Siddiqui. Computational Management Science 13 (1), 63-86

Artikel

Electricity industries worldwide have been restructured in order to introduce competition. As a result, decision makers are exposed to volatile electricity prices, which are positively correlated with those of natural gas in markets with price-setting gas-fired power plants. Consequently, gas-fired plants are said to enjoy a “natural hedge.” We explore the properties of such a built-in hedge for a gas-fired power plant via a stochastic programming approach, which enables characterisation of uncertainty in both electricity and gas prices in deriving optimal hedging and generation decisions. The producer engages in financial hedging by signing forward contracts at the beginning of the month while anticipating uncertainty in spot prices. Using UK energy price data from 2006 to 2011 and daily aggregated dispatch decisions of a typical gas-fired power plant, we find that such a producer does, in fact, enjoy a natural hedge, i.e., it is better off facing uncertain spot prices rather than locking in its generation cost. However, the natural hedge is not a perfect hedge, i.e., even modest risk aversion makes it optimal to use gas forwards partially. Furthermore, greater operational flexibility enhances this natural hedge as generation decisions provide a countervailing response to uncertainty. Conversely, higher energy-conversion efficiency reduces the natural hedge by decreasing the importance of natural gas price volatility and, thus, its correlation with the electricity price.

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Tradable Performance-Based CO₂ Emissions Standards

2016. Yihsu Chen, Makoto Tanaka, Afzal S. Siddiqui. Energy: Expectations and Uncertainty, 1-28

Konferens

Climate policy, like climate change itself, is subject to debate. Partially due to the political deadlock in Washington, DC, US climate policy, historically, has been driven mainly by state or regional effort until the recently introduced federal Clean Power Plan (CPP). Instead of a traditional mass-based standard, the US CPP stipulates a state-specific performance-based CO2 emission standard and delegates considerable flexibility to the states in achieving the standard. Typically, there are two sets of policy tools available: a tradable performance-based and a mass-based permit program. We analyze these two related but distinct standards when they are subject to imperfect competition in the product and/or permit markets. Stylized models are developed to produce general conclusions. Detailed models that account for heterogenous technologies and the transmission network are developed to evaluate policy efficiency. Depending on the scenarios under consideration, the resulting problem could be either a complementarity problem or a Stackelberg leaderfollower game, which is implemented as a mathematical program with equilibrium constraints (MPEC). We overcome the nonconvexity of MPECs by reformulating them as mixed integer problems. We show that while the cross-subsidy inherent in the performance-based standard that might effectively reduce power prices, it could inflate energy demand, thereby rendering permits scarce. When the leader in a Stackelberg formulation has a relatively clean endowment under the performancebased standard, its ability to manipulate the electricity market as well as to lower permit prices might worsen the market outcomes compared to its mass-based counterpart. On the other hand, when the leader has a relatively dirty endowment, the "cross-subsidy" could be the dominant force leading to a higher social welfare compared to the mass-based program. This paper contributes to the current policy debates in regulating emissions from the US power sector and highlights different incentives created by the mass- and performance-based standards.

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Fostering breakthrough technologies - How do optimal funding decisions depend on evaluation accuracy?

2015. Eeva Vilkkumaa (et al.). Technological forecasting & social change 96, 173-190

Artikel

There is a growing interest in fostering breakthrough technologies that offer exceptionally high value to society. However, when starting technology projects, it is impossible to know which of them have the potential to lead to breakthroughs. Therefore, organizations have adopted funding policies in which on-going projects are subjected to interim evaluations based on which some projects may be abandoned to release resources for seizing new opportunities. In this paper, we study which funding policies are optimal when the objective is either (i) to maximize the expected value of the project portfolio, or (ii) to maximize the expected number of exceptionally excellent projects that may lead to breakthrough technologies. We show that the optimal policy for funding exceptionally excellent projects is to start a large number of projects and abandon a high proportion of them later, whereas the optimal policy for maximizing the expected value of the project portfolio is to grant long-term funding to a smaller set of projects based on initial evaluation. Furthermore, we show how the trade-off between these two objectives depends on the initial project evaluation accuracy and the rate at which this accuracy improves. Our results suggest that this trade-off is particularly significant when the initial project evaluations are very uncertain but become more accurate soon after the projects have been launched. In such a setting, policies that seek to maximize the expected portfolio value may fail to promote breakthrough technologies.

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Transmission and Wind Investment in a Deregulated Electricity Industry

2015. Lajos Maurovich-Horvat, Trine Krogh Boomsma, Afzal Siddiqui. IEEE Transactions on Power Systems 30 (3), 1633-1643

Artikel

Adoption of dispersed renewable energy technologies requires transmission network expansion. Besides the transmission system operator (TSO), restructuring of electricity industries has introduced a merchant investor (MI), who earns congestion rents from constructing new lines. We compare these two market designs via a stochastic bi-level programming model that has either the MI or the TSO making transmission investment decisions at the upper level and power producers determining generation investment and operation at the lower level while facing wind power variability. We find that social welfare is always higher under the TSO because the MI has incentive to boost congestion rents by restricting capacities of transmission lines. Such strategic behavior also limits investment in wind power by producers. However, regardless of the market design (MI or TSO), when producers behave a la Cournot, a higher proportion of energy is produced by wind. In effect, withholding of generation capacity by producers prompts more transmission investment since the TSO aims to increase welfare by subsidizing wind and the MI creates more flow to maximize profit.

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When is it better to wait for a new version? Optimal replacement of an emerging technology under uncertainty

2015. Michail Chronopoulos, Afzal Siddiqui. Annals of Operations Research 235 (1), 177-201

Artikel

Firms that use an emerging technology often face uncertainty in both the arrival of new versions and the revenue that may be earned from their deployment. Via a sequential decision-making framework, we determine the value of the investment opportunity and the optimal replacement rule under three different strategies: compulsive, laggard, and leapfrog. In the first one, a firm invests sequentially in every version that becomes available, whereas in the second and third ones, it first waits for a new version to arrive and then either invests in the older or the newer version, respectively. We show that, under a compulsive strategy, technological uncertainty has a non-monotonic impact on the optimal investment decision. In fact, uncertainty regarding the availability of future versions may actually hasten investment. By comparing the relative values of the three strategies, we find that, under a low output price the compulsive strategy always dominates, whereas, at a high output price, the incentive to wait for a new version and adopt either a leapfrog or a laggard strategy increases as the rate of innovation increases. By contrast, high price uncertainty mitigates this effect, thereby increasing the relative attraction of a compulsive strategy.

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Capacity expansion and forward contracting in a duopolistic power sector

2014. Chin Dorea, Afzal Siddiqui. Computational Management Science 11 (1-2), 57-86

Artikel

The surge in demand for electricity in recent years requires that power companies expand generation capacity sufficiently. Yet, at the same time, energy demand is subject to seasonal variations and peak-hour factors that cause it to be extremely volatile and unpredictable, thereby complicating the decision-making process. We investigate how power companies can optimise their capacity-expansion decisions while facing uncertainty and examine how expansion and forward contracts can be used as suitable tools for hedging against risk under market power. The problem is solved through a mixed-complementarity approach. Scenario-specific numerical results are analysed, and conclusions are drawn on how risk aversion, competition, and uncertainty interact in hedging, generation, and expansion decisions of a power company. We find that forward markets not only provide an effective means of risk hedging but also improve market efficiency with higher power output and lower prices. Power producers with higher levels of risk aversion tend to engage less in capacity expansion with the result that together with the option to sell in forward markets, very risk-averse producers generate at a level that hardly varies with scenarios.

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Duopolistic competition under risk aversion and uncertainty

2014. Michail Chronopoulos, Bert De Reyck, Afzal Siddiqui. European Journal of Operational Research 236 (2), 643-656

Artikel

A monopolist typically defers entry into an industry as both price uncertainty and the level of risk aversion increase. By contrast, the presence of a rival typically hastens entry under risk neutrality. Here, we examine these two opposing effects in a duopoly setting. We demonstrate that the value of a firm and its entry decision behave differently with risk aversion and uncertainty depending on the type of competition. Interestingly, if the leader's role is defined endogenously, then higher uncertainty makes her relatively better off, whereas with the roles exogenously defined, the impact of uncertainty is ambiguous.

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Improving Energy Efficiency via Smart Building Energy Management Systems

2014. Paula Rocha, Afzal Siddiqui, Michael Stadler. Energy and Buildings 88, 203-213

Artikel

To foster the transition to more sustainable energy systems, policymakers have been approving measures to improve energy efficiency as well as promoting smart grids. In this setting, building managers are encouraged to adapt their energy operations to real-time market and weather conditions. Yet, most fail to do so as they rely on conventional building energy management systems (BEMS) that have static temperature set points for heating and cooling equipment. In this paper, we investigate how effective policy measures are at improving building-level energy efficiency compared to a smart BEMS with dynamic temperature set points. To this end, we present an integrated optimisation model mimicking the smart BEMS that combines decisions on heating and cooling systems operations with decisions on energy sourcing. Using data from an Austrian and a Spanish building, we find that the smart BEMS results in greater reduction in energy consumption than a conventional BEMS with policy measures.

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Optimizing Building Energy Operations via Dynamic Zonal Temperature Settings

2014. Markus Groissböck (et al.). Journal of energy engineering 140 (1)

Artikel

Deregulation of the energy sector has created new markets for producers as well as opportunities for consumers to meet their needs in a more customized way. Yet, traditional building energy management systems operate statically by adjusting air or water flow in heating and cooling systems in response to predetermined triggers, in relation to large deviations in the zone temperature from the equipment’s set-point temperature. The writers provide decision support to managers of buildings through dynamic control of the installed equipment that seeks to minimize energy costs. Assuming that the building’s occupants have comfort preferences expressed by upper and lower limits for the temperature, the writers model the effect of active equipment control (through changes to either the set point or valve flow) on the zone temperature, taking into account the external temperature, solar gains, building’s shell, and internal loads. The energy required to change the zone temperature in each time period is then used to calculate the energy cost in the objective function of an optimization problem. By implementing the model for actual public buildings, the writers demonstrate the advantages of more active equipment-management in terms of lower costs and energy consumption.

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Optionality and Policymaking in Re-Transforming the British Power Market

2014. Michail Chronopoulos, Derek Bunn, Afzal Siddiqui. Economics of Energy & Environmental Policy 3 (2), 79-100

Artikel

Conventional models to support policymaking for the energy sector have been largely based on deterministic or static settings that focus on planning welfare-maximising investment pathways. But, in a liberalised market, since investments are made by competitive, profit-maximising companies, the increased intervention of government policy in the trading arrangements creates uncertain responses to incentives. Industry may perceive policy risks to be high, and major companies may choose to act more cautiously than governments expect. This presents a modelling challenge, and we propose an extension to the use of real options in this context. We model several features of the low-carbon investment context, viz., irreversibility, delay, and competition, which impinge upon the radical policy imperatives for structural change in electricity markets to meet ambitious sustainability targets.

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Risk Averse Scheduling by a PEV Aggregator Under Uncertainty

2014. Ilan Momber (et al.). IEEE Transactions on Power Systems 30 (2), 882-891

Artikel

Research on electric power systems has considered the impact of foreseeable plug-in electric vehicle (PEV) penetration on its regulation, planning, and operation. Indeed, detailed treatment of PEV charging is necessary for efficient allocation of resources. It is envisaged that a coordinator of charging schedules, i.e., a PEV aggregator, could exercise some form of load control according to electricity market prices and network charges. In this context, it is important to consider the effects of uncertainty of key input parameters to optimization algorithms for PEV charging schedules. However, the modeling of the PEV aggregator's exposure to profit volatility has received less attention in detail. Hence, this paper develops a methodology to maximize PEV aggregator profits taking decisions in day-ahead and balancing markets while considering risk aversion. Under uncertain market prices and fleet mobility, the proposed two-stage linear stochastic program finds optimal PEV charging schedules at the vehicle level. A case study highlights the effects of including the conditional value-at-risk (CVaR) term in the objective function and calculates two metrics referred to as the expected value of aggregation and flexibility.

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Microgrid reliability modeling and battery scheduling using stochastic linear programming

2013. G. Cardoso (et al.). Electric power systems research 103, 61-69

Artikel

This paper describes the introduction of stochastic linear programming into Operations DER-CAM, a tool used to obtain optimal operating schedules for a given microgrid under local economic and environmental conditions. This application follows previous work on optimal scheduling of a lithium-iron-phosphate battery given the output uncertainty of a 1 MW molten carbonate fuel cell. Both are in the Santa Rita Jail microgrid, located in Dublin, California. This fuel cell has proven unreliable, partially justifying the consideration of storage options. Several stochastic DER-CAM runs are executed to compare different scenarios to values obtained by a deterministic approach. Results indicate that using a stochastic approach provides a conservative yet more lucrative battery schedule. Lower expected energy bills result, given fuel cell outages, in potential savings exceeding 6%.

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Optimizing Distributed Energy Resources, Passive Measures, and the daily Operation at Campus Pinkafeld

2013. M. Groissböck (et al.).

Konferens

Building managers and operators as at Campus Pinkafeld are interested in a cost optimal fulfilment of their energy needs. From a strategic point of view they are interested in optimal investments and upgrades. From an operative point of view they are interested in an optimal use of all available resources. This paper shows how the decision support system (DSS) of the project Energy Efficiency and Risk Management in Public Buildings (EnRiMa) will help with this challenges and the integration of the DSS with the existing energy management system (EMS) is one of the key issues for a successful project. The strategic DSS will inform the building owner about possible new technologies that might reduce the total building energy costs or environmental impact. The benefit of an operational DSS is to enable the building operator to use already adopted energy efficiency improving technologies as pre-cooling, pre-heating or any other demand response related tasks to decrease costs and emissions caused by the heating and cooling system of the building. Assuming an upper and lower limit for the room temperature, we model the effect of active equipment control (via changes to either the set point or the valve flow) on the zone temperature taking into account the external temperature, solar gains, the building shell, and internal loads. The energy required to change the zone temperature in each time period is then used to calculate the energy cost or efficiency in the objective function of an optimization problem. This paper reports on example results for Campus Pinkafeld, shows the technical approach, and that such a flexible approach can save 10% costs only on an operational level.

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The value of capacity sizing under risk aversion and operational flexibility

2013. Michail Chronoopoulos, Bert De Reyck, Afzal Siddiqui. IEEE transactions on engineering management 60 (2), 272-288

Artikel

Risk aversion typically erodes the value of an investment opportunity, often increasing the incentive to delay investment. Although this may be true when the decision maker has discretion only over the timing of investment, any additional discretion over the capacity of a project may lead to different results. In this paper, we extend the traditional real options approach by allowing for discretion over capacity while incorporating risk aversion and operational flexibility in the form of suspension and resumption options. In contrast to a project without scalable capacity, we find that increased risk aversion may actually facilitate investment because it decreases the optimal capacity of the project. Finally, we illustrate how the relative loss in the value of the investment opportunity due to an incorrect capacity choice may become less pronounced with increasing risk aversion and uncertainty.

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Transmission and wind investment in a deregulated electricity industry

2013. Lajos Maurovich-Horvat (et al.). 10th International Conference on the European Energy Market, 1-7

Konferens

The transition to a more sustainable energy system requires investment in renewable energy technologies such as wind. Due to the dispersed nature of sites for wind farms, concomitant expansionof the transmission network is also necessary. While the two objectives could be reconciled within the auspices of a regulated welfare-maximising planner, recent restructuring of electricity industries has introduced a merchant model for transmission investment, which provides congestion rents from construction of a new line. Thus, the merchant investor's incentives are different from those of producers carrying out investment in wind farms. In this paper, we analyse the interaction between the two conflicting objectives under various assumptions about the electricity market structure and the degree of producers' market power. Via a three-node illustrative example, we show that a merchant investor typically builds less transmission capacity than a welfare-maximising transmission system operator or central planner. Although social welfare is lower and nodal prices are generally higher with a merchant investor and when producers are assumed to behave à la Cournot, the effect of lower price response at the dominant demand node is to increase concentration of generation capacity. Hence, the distributional effects of transmission expansion depend on the relative supply-demand balance throughout the network.

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Capacity switching options under rivalry and uncertainty

2012. Afzal Siddiqui, Ryuta Takashima. European Journal of Operational Research 222 (3), 583-595

Artikel

Deregulated infrastructure industries exhibit stiff competition for market share. Firms may be able to limit the effects of competition by launching new projects in stages. Using a two-stage real options model, we explore the value of such flexibility. We first demonstrate that the value of investing in a sequential manner for a monopolist is positive but decreases with uncertainty. Next, we find that a typical duopoly firm's value relative to a monopolist's decreases with uncertainty as long as the loss in market share is high. Intriguingly, this result is reversed for a low loss in market share. We finally show that this loss in value is reduced if a firm invests in a sequential manner and specify the conditions under which sequential capacity expansion is more valuable for a duopolist firm than for a monopolist.

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Optimal Planning and Operation of Smart Grids with Electric Vehicle Interconnection

2012. M. Stadler (et al.). Journal of energy engineering 138 (2), 95-108

Artikel

Connection of electric storage technologies to smart grids will have substantial implications for building energy systems. Local storage will enable demand response. When connected to buildings, mobile storage devices, such as electric vehicles (EVs), are in competition with conventional stationary sources at the building. These EVs can change the financial and environmental attractiveness of on-site generation [e. g., photovoltaic (PV) or fuel cells (FCs)]. To examine the effect of EVs on building energy costs and carbon dioxide (CO2) emissions, a distributed-energy resources adoption problem is formulated as a mixed-integer linear program with minimization of annual building energy costs or CO2 emissions and solved for 2020 technology assumptions. The mixed-integer linear program is applied to a set of 139 different commercial buildings in California, and example results and the aggregated economic and environmental benefits are reported. Special constraints for the available PV, solar thermal, and EV parking lots at the commercial buildings are considered. The research shows that EV batteries can be used to reduce utility-related energy costs at the smart grid or commercial building due to arbitrage of energy between buildings with different tariffs. However, putting more emphasis on CO2 emissions makes stationary storage more attractive, and stationary storage capacities increase, whereas the attractiveness of EVs decreases. The limited availability of EVs at the commercial building decreases the attractiveness of EVs, and if PV is chosen by the optimization, then it is mostly used to charge the stationary storage at the commercial building and not the EVs connected to the building. DOI: 10.1061/(ASCE)EY.1943-7897.0000070.

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Real options analysis of investment in carbon captureand sequestration technology

2012. Somayeh Heydari, Nick Ovenden, Afzal Siddiqui. Computational Management Science 9 (1), 109-138

Artikel

Among a comprehensive scope of mitigation measures for climate change, CO₂ capture and sequestration (CCS) plays a potentially significant role in industrialised countries. In this paper, we develop an analytical real options model that values the choice between two emissions-reduction technologies available to a coal-fired power plant. Specifically, the plant owner may decide to invest in either full CCS (FCCS) or partial CCS (PCCS) retrofits given uncertain electricity, CO₂, and coal prices. We first assess the opportunity to upgrade to each technology independently by determining the option value of installing a CCS unit as a function of CO₂ and fuel prices. Next, we value the option of investing in either FCCS or PCCS technology. If the volatilities of the prices are low enough, then the investment region is dichotomous, which implies that for a given fuel price, retrofitting to the FCCS (PCCS) technology is optimal if the CO₂ price increases (decreases) sufficiently. The numerical examples provided in this paper using current market data suggest that neither retrofit is optimal immediately. Finally, we observe that the optimal stopping boundaries are highly sensitive to CO₂ price volatility.

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Control of greenhouse gas emissions by optimal DER technology investment and energy management in zero-net-energy buildings

2011. Michael Stadler (et al.). European transactions on electrical power 21 (2), 1291-1309

Artikel

The U.S. Department of Energy has launched the commercial building initiative (CBI) in pursuit of its research goal of achieving zero-net-energy commercial buildings (ZNEB), i.e., ones that produce as much energy as they use. Its objective is to make these buildings marketable by 2025 such that they minimize their energy use through cutting-edge, energy-efficiency technologies and meet their remaining energy needs through on-site renewable energy generation. This paper examines how such buildings may be implemented within the context of a cost-or CO(2)-minimizing microgrid that is able to adopt and operate various technologies: photovoltaic (PV) modules and other on-site generation, heat exchangers, solar thermal collectors, absorption chillers, and passive/demand-response technologies. A mixed-integer linear program (MILP) that has a multi-criteria objective function is used. The objective is minimization of a weighted average of the building's annual energy costs and CO(2) emissions. The MILP's constraints ensure energy balance and capacity limits. In addition, constraining the building's energy consumed to equal its energy exports enables us to explore how energy sales and demand-response measures may enable compliance with the ZNEB objective. Using a commercial test site in northern California with existing tariff rates and technology data, we find that a ZNEB requires ample PV capacity installed to ensure electricity sales during the day. This is complemented by investment in energy-efficient combined heat and power (CHP) equipment, while occasional demand response saves energy consumption. A large amount of storage is also adopted, which may be impractical. Nevertheless, it shows the nature of the solutions and costs necessary to achieve a ZNEB. Additionally, the ZNEB approach does not necessary lead to zero-carbon (ZC) buildings as is frequently argued. We also show a multi-objective frontier for the CA example, which allows us to estimate the needed technologies and costs for achieving a ZC building or microgrid.

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Optimal investment under operational flexibility, risk aversion, and uncertainty

2011. Michail Chronopoulos, Bert De Reyck, Afzal Siddiqui. European Journal of Operational Research 213 (1), 221-237

Artikel

Traditional real options analysis addresses the problem of investment under uncertainty assuming a risk-neutral decision maker and complete markets. In reality, however, decision makers are often risk averse and markets are incomplete. We confirm that risk aversion lowers the probability of investment and demonstrate how this effect can be mitigated by incorporating operational flexibility in the form of embedded suspension and resumption options. Although such options facilitate investment, we find that the likelihood of investing is still lower compared to the risk-neutral case. Risk aversion also increases the likelihood that the project will be abandoned, although this effect is less pronounced. Finally, we illustrate the impact of risk aversion on the optimal suspension and resumption thresholds and the interaction among risk aversion, volatility, and optimal decision thresholds under complete operational flexibility.

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The effect of missing data on wind resource estimation

2011. Aidan Coville, Afzal Siddiqui, Klaus-Ole Vogstad. Energy 36 (7), 4505-4517

Artikel

Investment in renewable energy sources requires reliable data. However, meteorological datasets are often plagued by missing data, which can bias energy resource estimates if the missingness is systematic. We address this issue by considering the influence of missing data due to icing of equipment during the winter on the wind resource estimation for a potential wind turbine site in Norway. Using a mean-reverting jump-diffusion (MRJD) process to model electricity prices, we also account for the impact on the expected revenue from a wind turbine constructed at the site. While missing data due to icing significantly bias the wind resource estimate downwards, their impact on revenue estimates is dampened because of volatile electricity spot prices. By contrast, with low-volatility electricity prices, the effect of missing data on revenue estimates is highly significant. The seasonality-based method we develop removes most of the bias in wind resource and revenue estimation caused by missing data.

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Transmission Capacity between Norway and Germany - a Real Options Analysis

2011. Stein-Erik Fleten, Heggedal Ane Marte, Afzal Siddiqui. Journal of Energy Markets 4 (1), 121-147

Artikel

Interconnection of two electricity markets provides revenues to the owner of the line. In this paper we study the alternatives open to an investor holding a unique right to construct transmission capacity between Norway and Germany. The alternatives are either constructing a 700 MW cable with a subsequent expansion option, or to construct a 1400 MW cable. We use a real options valuation (ROV) framework to decide which capacity should be chosen, and when the investment should be carried through. Our scientific contribution is to apply the ROV framework where sequential investment is allowed on transmission capacity investment. Further, we combine information from a bottom-up model, which estimates the reduction in average price differences due to the investment itself, and a top-down model for finding the values and optimal decisions.

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Afzal SiddiquiProfessor

Forskningsprojekt

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Optimal investment under operational flexibility, risk aversion, and uncertainty

The effect of missing data on wind resource estimation

Transmission Capacity between Norway and Germany - a Real Options Analysis

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