|   | 
Details
   web
Records
Author Fernandez, M.; Munoz, F.D.; Moreno, R.
Title Analysis of imperfect competition in natural gas supply contracts for electric power generation: A closed-loop approach Type
Year 2020 Publication Energy Economics Abbreviated Journal Energy Econ.
Volume 87 Issue Pages (up) 15 pp
Keywords Market power; Natural gas; Electricity market; Generalized Nash equilibrium; Equilibrium Problem with Equilibrium; Constraints
Abstract The supply of natural gas is generally based on contracts that are signed prior to the use of this fuel for power generation. Scarcity of natural gas in systems where a share of electricity demand is supplied with gas turbines does not necessarily imply demand rationing, because most gas turbines can still operate with diesel when natural gas is not available. However, scarcity conditions can lead to electricity price spikes, with welfare effects for consumers and generation firms. We develop a closed-loop equilibrium model to evaluate if generation firms have incentives to contract or import the socially-optimal volumes of natural gas to generate electricity. We consider a perfectly-competitive electricity market, where all firms act as price-takers in the short term, but assume that only a small number of firms own gas turbines and procure natural gas from, for instance, foreign suppliers in liquefied form. We illustrate an application of our model using a network reduction of the electric power system in Chile, considering two strategic firms that make annual decisions about natural gas imports in discrete quantities. We also assume that strategic firms compete in the electricity market with a set of competitive firms do not make strategic decisions about natural gas imports (i.e., a competitive fringe). Our results indicate that strategic firms could have incentives to sign natural gas contracts for volumes that are much lower than the socially-optimal ones, which leads to supernormal profits for these firms in the electricity market. Yet, this effect is rather sensitive to the price of natural gas. A high price of natural gas eliminates the incentives of generation firms to exercise market power through natural gas contracts. (C) 2020 Elsevier B.V. All rights reserved.
Address [Fernandez, Mauricio; Munoz, Francisco D.] Univ Adolfo Ibanez, Fac Ingn & Ciencias, Santiago, Chile, Email: fdmunoz@uai.cl
Corporate Author Thesis
Publisher Elsevier Place of Publication Editor
Language English Summary Language Original Title
Series Editor Series Title Abbreviated Series Title
Series Volume Series Issue Edition
ISSN 0140-9883 ISBN Medium
Area Expedition Conference
Notes WOS:000536091600026 Approved
Call Number UAI @ eduardo.moreno @ Serial 1196
Permanent link to this record
 

 
Author Munoz, F.D.; Wogrin, S.; Oren, S.S.; Hobbs, B.F.
Title Economic Inefficiencies of Cost-based Electricity Market Designs Type
Year 2018 Publication Energy Journal Abbreviated Journal Energy J.
Volume 39 Issue 3 Pages (up) 51-68
Keywords Electricity market design; market power; equilibrium modeling; opportunity costs
Abstract Some restructured power systems rely on audited cost information instead of competitive bids for the dispatch and pricing of electricity in real time, particularly in hydro systems in Latin America. Audited costs are also substituted for bids in U.S. markets when local market power is demonstrated to be present. Regulators that favor a cost-based design argue that this is more appropriate for systems with a small number of generation firms because it eliminates the possibilities for generators to behave strategically in the spot market, which is a main concern in bid-based markets. We discuss existing results on market power issues in cost- and bid-based designs and present a counterintuitive example, in which forcing spot prices to be equal to marginal costs in a concentrated market can actually yield lower social welfare than under a bid-based market design due to perverse investment incentives. Additionally, we discuss the difficulty of auditing the true opportunity costs of generators in cost- based markets and how this can lead to distorted dispatch schedules and prices, ultimately affecting the long-term economic efficiency of a system. An important example is opportunity costs that diverge from direct fuel costs due to energy or start limits, or other generator constraints. Most of these arise because of physical and financial inflexibilities that become more relevant with increasing shares of variable and unpredictable generation from renewables.
Address [Munoz, Francisco D.] Univ Adolfo Ibanez, Fac Ingn & Ciencias, Santiago, Chile, Email: fdmunoz@uai.cl
Corporate Author Thesis
Publisher Int Assoc Energy Economics Place of Publication Editor
Language English Summary Language Original Title
Series Editor Series Title Abbreviated Series Title
Series Volume Series Issue Edition
ISSN 0195-6574 ISBN Medium
Area Expedition Conference
Notes WOS:000431395500003 Approved
Call Number UAI @ eduardo.moreno @ Serial 851
Permanent link to this record
 

 
Author Perez, A.P.; Sauma, E.E.; Munoz, F.D.; Hobbs, B.F.
Title The Economic Effects of Interregional Trading of Renewable Energy Certificates in the US WECC Type
Year 2016 Publication Energy Journal Abbreviated Journal Energy J.
Volume 37 Issue 4 Pages (up) 267-295
Keywords Renewable Portfolio Standards; Renewable Energy Credits; Transmission planning; Western Electricity Coordinating Council; Electricity markets
Abstract In the U.S., individual states enact Renewable Portfolio Standards (RPSs) for renewable electricity production with little coordination. Each state imposes restrictions on the amounts and locations of qualifying renewable generation. Using a co-optimization (transmission and generation) planning model, we quantify the long run economic benefits of allowing flexibility in the trading of Renewable Energy Credits (RECs) among the U.S. states belonging to the Western Electricity Coordinating Council (WECC). We characterize flexibility in terms of the amount and geographic eligibility of out-of-state RECs that can be used to meet a state's RPS goal. Although more trade would be expected to have economic benefits, neither the size of these benefits nor the effects of such trading on infrastructure investments, CO2 emissions and energy prices have been previously quantified. We find that up to 90% of the economic benefits are captured if approximately 25% of unbundled RECs are allowed to be acquired from out of state. Furthermore, increasing REC trading flexibility does not necessarily result in either higher transmission investment costs or a substantial impact on CO2 emissions. Finally, increasing REC trading flexibility decreases energy prices in some states and increases them elsewhere, while the WECC-wide average energy price decreases.
Address [Perez, Andres P.; Sauma, Enzo E.] Pontificia Univ Catolica Chile, Ind & Syst Engn Dept, Santiago, Chile, Email: esauma@ing.puc.cl
Corporate Author Thesis
Publisher Int Assoc Energy Economics Place of Publication Editor
Language English Summary Language Original Title
Series Editor Series Title Abbreviated Series Title
Series Volume Series Issue Edition
ISSN 0195-6574 ISBN Medium
Area Expedition Conference
Notes WOS:000385912700012 Approved
Call Number UAI @ eduardo.moreno @ Serial 666
Permanent link to this record
 

 
Author Ciarreta, A.; Nasirov, S.; Silva, C.
Title The development of market power in the Spanish power generation sector: Perspectives after market liberalization Type
Year 2016 Publication Energy Policy Abbreviated Journal Energy Policy
Volume 96 Issue Pages (up) 700-710
Keywords Competition; Market power; Spanish electricity market
Abstract This paper provides a comprehensive analysis of the market power problem in the Spanish power generation sector and examines how and to which extent the market has developed in terms of market power concerns after the market liberalization reforms. The methodology applied in this study includes typical ex-post structural and behavioral measures employed to estimate potential for market power, namely: concentration ratios (CR) (for the largest and the three largest suppliers), the Herfindahl-Hirschman Index (HHI), Entropy, Pivotal Supply Index, the Residual Supply Index and Residual Demand Elasticity (RDE). The results are presented for the two largest Spanish generating companies (Endesa and Iberdrola) acting in the Iberian Electricity Market (MIBEL), and in the Spanish Day-ahead electricity market. The results show evidence that these companies have behaved much more competitively in recent periods than in the beginning of the market liberalization. In addition, the paper discusses important structural and regulatory changes through market liberalization processes in the Spanish Day ahead electricity market. (C) 2016 Elsevier Ltd. All rights reserved.
Address [Ciarreta, Aitor] Univ Basque Country, Dept Fundamentos Anal Econ 2, BETS, Avda Lehendakari Aguirre 83, Bilbao 48015, Spain, Email: aitor.ciarreta@ehu.es;
Corporate Author Thesis
Publisher Elsevier Sci Ltd Place of Publication Editor
Language English Summary Language Original Title
Series Editor Series Title Abbreviated Series Title
Series Volume Series Issue Edition
ISSN 0301-4215 ISBN Medium
Area Expedition Conference
Notes WOS:000381530700057 Approved
Call Number UAI @ eduardo.moreno @ Serial 650
Permanent link to this record
 

 
Author Villalobos, C.; Negrete-Pincetic, M.; Figueroa, N.; Lorca, A.; Olivares, D.
Title The impact of short-term pricing on flexible generation investments in electricity markets Type
Year 2021 Publication Energy Economics Abbreviated Journal Energy Econ.
Volume 98 Issue Pages (up) 105213
Keywords Electricity markets; Pricing schemes; Market incentives; Flexibility; Renewable energy
Abstract The massive growth in the integration of variable renewable energy sources is producing several challenges in the operation of power systems and its associated markets. In this context, flexibility has become a critical attribute to allow the system to react to changes in generation or demand levels. Thus, it is critical for market signals at both short and long term scales to include flexibility features, to align agents' incentives with systemic flexibility requirements. In this paper, different pricing schemes for short-term markets are studied, based on various relaxations of the unit commitment problem, including convex-hull approximations, with the aim of representing operational flexibility requirements in a more explicit way. Extensive simulations illustrate the performance of the proposed schemes, as compared to conventional ones, in terms of the capability of the system to properly incentivize flexibility attributes, resulting in better agents' cost recovery and more variable renewable energy utilization. The results show that short-term pricing schemes considered improve the long-term signals for flexible investments but additional changes to market design are still required. Thus, there is a need to revisit historical practices for pricing rules by incorporating additional flexibility-related attributes into them. Several alternatives are discussed and policy recommendations based on these considerations are provided.
Address
Corporate Author Thesis
Publisher Place of Publication Editor
Language Summary Language Original Title
Series Editor Series Title Abbreviated Series Title
Series Volume Series Issue Edition
ISSN 0140-9883 ISBN Medium
Area Expedition Conference
Notes Approved
Call Number UAI @ alexi.delcanto @ Serial 1401
Permanent link to this record