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The stated aim of the European Commission has been the unbounded flow of energy across Europe and the effective functioning of a single European power market so as to achieve secure, sustainable and affordable energy supplies, as well as to foster competition and increase the utilization of electricity networks and generation capacity. Most countries have already adapted or are gradually adapting their wholesale markets to the provisions of the so called Target Model for the internal electricity market in Europe, however Greece still lies behind in this binding target. In this paper, the basic design variables and respective options for the integration of the Greek wholesale electricity market with the other European markets under the Target Model paradigm are presented. The design variables refer to all market instances and mechanisms. The proposed choices are justified in terms of effectiveness and market power mitigation, considering the current market structure in Greece. A transitional phase for the full integration of the Greek Intraday and Balancing Markets is proposed, considering the relevant evolutions in the wholesale markets of Greece’s neighboring countries. Finally, a simulation analysis is performed in order to highlight the implications on schedules of utilizing European-based order formats in the restructured Greek electricity market.

In centralized day-ahead electricity markets with marginal pricing, unit commitment costs and capacity constraints give rise to non-convexities which may result in losses to some of the participating generating units. To compensate them for these losses, a recovery mechanism is required. In Part I of this two-part paper, we present certain recovery mechanisms that result in recovery payments after the market is cleared. We also propose a methodology for evaluating the bidding strategy behavior of the participating units for each mechanism. In this paper (Part II), we apply this methodology to evaluate the performance and incentive compatibility properties of each recovery mechanism on a test case model representing the Greek joint energy/reserve day-ahead electricity market. Lastly, we perform sensitivity analysis with respect to key parameters and assumptions and we provide directions for further research.

In centralized day-ahead electricity markets with marginal pricing, unit commitment costs and capacity constraints give rise to non-convexities which may result in losses to some of the participating generating units. Therefore, a recovery mechanism is required to compensate them. In this paper, we present and analyze several recovery mechanisms that result in recovery payments after the market is cleared. Each of these mechanisms results in a different type and/or amount of payments for each participating unit that exhibits losses. We also propose a methodology for evaluating the bidding strategy behavior of the participating units for each mechanism. This methodology is based on the execution of a numerical procedure aimed at finding joint optimal bidding strategies of the profit-maximizing units. In a companion follow-up paper (Part II), we apply this methodology to evaluate the performance and incentive compatibility of the suggested recovery mechanisms on a simplified test case model of the Greek electricity market.

In this paper we consider the effects of the transmission grid on the operational system flexibility and evaluate the trade-offs between various options including committing flexible generation, curtailing Renewable Energy Sources (RES) generation, or allowing flexibility violations in the form of ramping up/down requirements in the presence of high penetration of renewable generation. All ISO/TSO markets in the different time scales are considered in this study, namely the Day Ahead Market (DAM), Hour Ahead Market (HAM) and Real-Time Market (RTM). Our proposed methodology is based on the co-optimization of energy and ancillary services. We deployed the Mixed Integer Programming (MIP) Security Constrained Unit Commitment (SCUC) and the Security Constrained Economic Dispatch (SCED) functions applied to all wholesale energy markets in sequence as they are executed in practice today. This paper describes the proposed methodology and presents numerical results resulting from detailed energy simulations applied to the California ISO energy market. The deployment of a detailed transmission model, the implementation of a new Flexible Ramping AS, and the accurate transition between DAM to HAM to RTM markets are the key original contributions of this paper.

This paper studies the management of costs associated with transmission constraints (i.e., transmission congestion costs) in a competitive electricity market. The paper examines two approaches for dealing with these costs. The first approach is based on a nodal pricing framework and forms the basis of the so-called pool model. The paper also provides an analysis of financial instruments proposed to complement nodal pricing and includes illustrative test results on a large scale system. The second approach is based on cost allocation procedures proposed for the so-called bilateral model. The paper explains the basis for this model including a game-theoretic evaluation of some of its aspects. Both the pool and bilateral models have been at the center of the electric utility restructuring debate in California.

In this paper, we address the recently established regulatory framework for the management of the Greek Non-Interconnected Islands (NII) power systems. We present the recent initiatives for the development of Energy Control Centers, including Energy and Market Management Systems, and we provide an overview of the proposed systems architecture. In addition, we list a formulation of the basic market process for the implementation of a NII electricity market, i.e., the Rolling Day-Ahead Scheduling, which captures key features of the regulatory framework. To illustrate the model, we use as a test case a particular NII.

This paper is based on material presented at the IEEE 1995 Winter Power Meeting Panel Session on Challenges to optimal power flow (OPF), sponsored by the IEEE working group on operating economics. The paper contains a brief summary of the session followed by summaries. The sessions covered are: an OPF user's perspective; challenges from a planning perspective; extended applications of OPF; OPF application in deregulated electricity market; challenges to on-line OPF implementation; and control applications of OPF in EMS.

The Greek wholesale electricity market is based on a day-ahead unit commitment market clearing and generation dispatch formulation with co-optimization of energy and reserves without the participation of transmission. An important feature of the market design is the cost recovery mechanism, which explicitly compensates generation units for their commitment costs and guarantees a minimum profit equal to 10% of their variable costs. In this paper, we evaluate the current mechanism in comparison to an alternative bid/cost recovery mechanism by simulating the wholesale electricity market for a period of one year. As part of the study we take into account the forthcoming changes for the liberalization of the Greek market that include the physical and virtual sale of a portion of PPC lignite plants, and we examine a likely "business as usual" scenario concerning the resulting bidding strategies. Lastly, we perform a sensitivity analysis with respect to the hydro production and the carbon price. (6 pages)

In wholesale electricity markets, unit commitment costs and capacity constraints create non-convexities which may bring about losses to some of the participating generation units. To keep the losing units in the market, a recovery mechanism that makes them whole is needed. In this paper, we present a recovery mechanism which compensates the units that incur cost-based losses with recovery payments, in order to ensure that they end up with positive profits. The profits resulting from the recovery payments are loss-related. More specifically, a losing unit will receive recovery payments to end up with final net profits that are set to a percentage, say α, of the losses. We evaluate this mechanism with a simulation-based methodology for certain values of the regulating parameter ??, and the results show that this mechanism produces relatively low uplifts. We also comment on the pros and cons of this design and provide directions for further research.

The goal of this paper is to evaluate the incentive compatibility of several cost- and bid-based recovery mechanisms that may be implemented in a wholesale electricity market to make the generation units whole in the presence of non-convexities, which are due to unit commitment costs and capacity constraints. To this end, we simulate the bidding behavior of the participants in a simplified model of the Greek joint energy/reserve day-ahead electricity market, where we assume that the players (units) participate as potential price-makers in a non-cooperative game with complete information that is repeated for many rounds. The results suggest that a mechanism based on bid recovery with a regulated cap is quite promising.

This paper presents a methodology along with practical implementation considerations for performing energy market simulations of co-optimized Energy and Ancillary Services markets with and without full and detailed transmission representation for various applications. The inclusion of full transmission representation leads to Locational Marginal Pricing (LMP) based energy market models that are widely used in the United States. Exclusion of the network along with certain other simplifications leads to energy market models widely used in Europe. In either case, the modeling formulation of the Market Simulation is provided in the paper along with insights about the factors that mainly influence the prices in nodal (i.e., LMP) and zonal energy markets. Representative numerical results from the application of the proposed methodology on two different studies of the Greek National Energy Market are also presented. (7 pages)

This paper presents the methodology for performing market simulations for Locational Marginal Price (LMP) forecasting in nodal energy markets. The modeling formulation of the Market Simulation is provided in t he paper along with insights about factors that mainly influence the LMP prices in nodal energy markets. Representative numerical results from the application of the proposed methodologies on the actual California system and the Greek National market are also presented.

Greece's electricity market is divided in two zones, North and South, due to a generation-consumption system configuration that creates a significant transmission bottleneck from North to South. Clearly, a zonal pricing approach for energy provides the right incentive for the installation of new generation near consumption, if the zonal configuration reflects actual system and operational conditions. In this paper, we extend the zonal approach to include the time response-based ancillary services (also called “reserves”), which are commodities that are traded in the day-ahead market and are co-optimized with energy. We focus on the Day-Ahead Scheduling (DAS) market problem, which we formulate as a Security-Constrained Unit-Commitment problem whose objective is to co-optimize energy and reserves, taking into account the generation units' commitment costs. We model the DAS market problem as a Mixed-Integer Linear Programming problem that is solved every day, simultaneously for all 24 hours of the next day. Dual analysis of the problem and calculation of shadow prices provides useful insight on how prices for each commodity are set in the presence of binding resource, transmission or zonal reserve constraints. We use a simplified model of the Greek electricity system that includes only thermal plants to illustrate the developed methodology, the resulting market solutions and unit schedules, and the energy and ancillary services marginal prices. We also analyze and discuss issues such as the interaction between the commodities of energy and ancillary services under the marginal pricing approach.

Ancillary services are essential to the reliability and security of power system operation in any competitive electricity market environment. This paper discusses various AS market design options for procuring, pricing and settling ancillary services via competitive auctions by an independent system operator (ISO). The paper also discusses problems and potential solutions associated with these market design options based on actual experience of operating ISOs. These problems include price volatility and spikes and price reversals for the various components of the ancillary services that can create perverse incentives in the marketplace. Further we elaborate on the design that has been proven so far based on practical experience to be the most efficient.

This paper elaborates on the basic characteristics of these diverse power market design models and the lessons learned based on actual practical experience. We'll take into account the peculiar features of the electricity industry, including the temporal and stochastic variability of demands and supplies, accentuated by the non-storability of power, multiple technologies with varying sensitivities to capital and fuel costs and environmental and siting restrictions, and dependence on a reliable and secure transmission system. The economic problems include substantial non-convexities (immobility of generation and transmission faculties, scale economies in generation, non-linearities in transmission), and externalities (mainly in transmission). As regards generation these problems have eased sufficiently in recent decades to enable competitive energy markets, but they remain important considerations in designing these markets.

This paper presents the methodology and the results of the must offer waiver process as applied in the California electricity market. The goal of this cost saving process is to minimize the market operation costs by deploying an optimal unit commitment approach. This procedure replaces the "first come, first served" must offer waiver process that is currently in place. It uses a security constrained unit commitment application to commit enough units to meet the reliability requirement and minimize the total start up and minimum load costs over the specified time period. A post must offer waiver procedure utilizing the security constrained unit commitment is also established to calculate and allocate the incremental costs associated with the local reliability requirement. The key components of the new must offer waiver procedure, the methodology and computer algorithm of security constrained unit commitment, and the methodology of the incremental cost calculation and allocation are addressed in this paper. The paper finally presents computational results based on actual data to illustrate the benefits of the new approach

Deregulation of electricity markets has substantially increased the need for analytical modeling and advanced software. Today's Independent System Operators and Power Exchanges use very sophisticated software based on advanced analytical models to administer various markets for delivery of various products and services. In California, the IS0 is charged with the competitive procurement of various products including ancillary services, transmission rights and real time imbalance energy in the various forward and real time markets. The Power Exchange is charged with the procurement and pricing of forward energy. This talk will address the design of market mechanisms for the efficient procurement, pricing and settlements of those products and services and the use of very sophisticated methodologies and software that runs periodically to support the management of these markets. In particular I will focus on the design, the analytical modeling requirements and the main characteristics of the software used to clear the auctions for commodities in all three markets, Day-Ahead, Hour-Ahead and Real-Time markets. Extensions will be made to cover the design and the analytical modeling aspects of other lSOs currently operating or under development in North America.

This paper presents the fundamental elements of a well functioning financial transmission rights (FTR) market that is necessary for supporting wholesale competitive electricity markets. Emphasis is placed on the practical considerations that need to be carefully evaluated in implementing an FTR market. The paper presents an analysis of the FTR procurement alternatives market participants can deploy for procuring financial instruments as part of their hedging strategy. The paper focuses on the FTR allocation approach as a key methodology for procuring FTRs. Two main considerations are presented; the eligibility rules and the validation rules. The paper finally presents various allocation methodologies and an analysis of the incentives of the associated objective formulations. A numerical example is presented to illustrate the market benefits of the simulated auction single round approach over the least squares approach with sequential rounds.

Ancillary services are essential to the reliability and security of power system operation in any competitive electricity market environment. Procurement of ancillary services must take into account effective use of the capacity under emergency conditions, delivery time, transmission limitations, and local area requirements. Regional procurement of ancillary services is an approach that results in effective distribution of reserves and ensures continuous reliability in the event of a contingency occurring anywhere in the system. However, most ISOs procure and price ancillary services based on the least-cost service with little regard to zonal dispersion. In general, such an approach is not sufficient to ensure continuous reliability and security of the power system This paper presents a new methodology and numerical examples for procuring and pricing ancillary services on a regional basis, with an explicit representation of imports in a simultaneous energy/reserve market environment.

Summary form only given as follows. The FERC in its RTO Order 2000 reaffirms the requirement that an RTO must (1) encourage market-motivated operating and investment actions for preventing and relieving congestion; (2) accommodate efforts by state regulatory commissions to create multi-state agreements to review and approve new transmission facilities, coordinated with programs of existing Regional Transmission Groups (RTGs) where necessary; and (3) file a plan with the FERC with specified milestones that will ensure that it meets the overall planning and expansion requirement no later than three years after initial operation, if the RTO is unable to satisfy this requirement when it commences operation. In the alternative, the RTO must demonstrate that an alternative proposal is consistent with or superior to these three requirements. The FERC expresses its preference for market-based plans, and noted that the pricing mechanisms and actions used by the RTO as part of its transmission planning and expansion program should be compatible with the pricing signals for shorter-term solutions to transmission constraints (i.e., congestion management) so that market participants can choose the least-cost response. Development and implementation of transmission projects remains a major challenge in the new competitive environment. Alternative business models including RTOs, and Transcos have been proposed as the best infrastructure under which appropriate transmission investments can be made to ensure the security of the transmission grid at least cost. This presentation discusses the various analytical approaches for evaluating prospective transmission projects. Two areas of particular difficulty are also discussed. These are: dealing with uncertainty and the interdependence of transmission and generation investment. Finally, the incorporation of market power in the wholesale electricity market into the transmission evaluation process is also discussed.

This paper discusses alternative design options for a real-time balancing market operated by an independent system operator (ISO). The market design can vary based on a number of criteria such as the role of centralized dispatch, the incidence of price overlaps in bids, the use of penalties, the representation of the transmission network, and the effects of ramping constraints. The paper discusses how price overlaps can be eliminated and how market participants can trade imbalances at ex-post prices in the forward market.