A comprehensive strategy for transmission switching action in simultaneous clearing of energy and spinning reserve markets

There is a great resolution calling for smart grids in recent years. Introduction of new technologies, that make the network flexible and controllable, is a main part of smart grid concept and a key factor to its success. Transmission network as a part of system network has drawn less attention. Transmission switching as a new transmission service can release us from load shedding and remove the constraints’ violations.Transmission switching can provide economic benefits compared to other control methods such as generation unit rescheduling or load shedding for contingency management.Utilizing a stochastic mix-integer nonlinear programming (SMINLP) model, transmission switching is used during contingencies and steady state to determine optimal required energy and reserve values.Stochastic joint energy and reserve markets with transmission switching considering dynamic constraints has been proposed to minimize the cost of supplying load, security expenses.Considering dynamic constraints in proposed model avoid the occurrence of transient instability when opening the line in transmission switching action.A network reduction method based on modified Jacobean AC Newton–Raphson technique power flow considering switchable line in technique is used for speeding up the calculation, efficiency and simplicity.To investigate the efficiency of the proposed strategy IEEE 14 bus test and IEEE 57 bus test system are studied. According to the obtained results, this strategy decreases energy and reserve marginal prices, as well as security cost.     

An optimal pricing scheme in electricity markets by parallelizing security constrained optimal power flow based market-clearing model

To improve economic efficiency of electricity markets, the market-clearing model must be designed to give transparent information for pricing system security and to quantify the correlation between the market operations and the power systems operations, which is an immensely provocative and challenging issue in electricity markets. This paper sets out to propose a novel approach to pricing the system security by parallelizing the security constrained optimal power flow (SCOPF) based market-clearing model, while providing market solutions as a function of complying with the required voltage security margin and N-1 contingency criteria. The proposed SCOPF based market-clearing framework also takes into consideration the bilateral transaction information and, at the same time, optimal pricing expressions through computing locational marginal prices (LMPs) and nodal congestion prices (NCPs) for ensuring voltage security are derived. The results from a 129-bus model of the Italian HV transmission system turn out to be the validity of the proposed market-clearing model for managing and pricing the system security.     

Comparison of transmission pricing models

In this paper we make a comparison of three transmission pricing models: the Wangensteen model, the optimal power flow model and the Hogan model. The similarities among the models are that all can be used in locational pricing systems. In these systems the prices are calculated as the marginal cost that in turn equals the marginal benefit to load. In the Wangensteen model and the original optimal power flow model, the locational prices are equal to the Lagrange multipliers associated with the power flow equations. On the contrary, Hogan’s model and the modified optimal power flow model express the locational prices as equal to the reference bus (node) price, the marginal costs of losses, and the marginal costs of congestion. The Wangensteen model is used for educational purposes and considers elastic load. The optimal power flow model has been widely used in electrical engineering and dispatch of power systems. Load is assumed to be inelastic. Hogan’s model is an economist’s version of the optimal power flow model and considers elastic load. It also gives an expression for the locational prices in terms of an equilibrium equation.     

当量电价体系及相关制度设计:(八)双边交易过网服务中含运行备用的当量电价法

在库联营基础上开放双边交易有重要的市场意义，然而其过网服务定价却是一个复杂问题。文中论述了过网费中应包括的6项主要成分，即输电线路运行和投资的2项回收成本，网络阻塞和优化调度的2项机会成本，以及运行备用和自动发电控制(AGC)的2项辅助服务成本，这2项辅助服务都是交易中心购自库联营发电并通过输电网提供的。前4项基本的回收成本和机会成本都已在输电当量电价中计入，而AGC辅助服务适合另行单独定价和考核。文中主要介绍了包含运行备用辅助服务的双边交易过网服务的当量电价方法。算例给出了不合和含运行备用的过网电价的日变化曲线及其成分，表明在过网电价中自动包含运行备用辅助服务成本是必要的、可行的；还表明在过网主要路径附近存在阻塞时，过网费率灵敏于负荷水平和过网节点，从而展现了当量电价方法解决这类复杂问题的优越性。     

集成定价法在输电电价中的应用

对输电电价的定价方法进行了研究,对输电网的成本进行了分析,将其成本分为固定成本和变动成本2大类,固定成本基本上不随时间变化,变动成本随时间变化而不断改变。提出了集成定价思想,即对输电网的固定成本采用综合成本定价法,按最大需量进行分摊,而对变动成本则采用基于边际成本定价法的实时电价并进行实时分摊,两者有效结合即得出输电网的电价模型。该模型可称为集成定价法下的节点电价模型,可以应用于实时电价、分时电价、日前市场电价和远期合同电价。通过算例说明了该电价模型的具体应用。     

电力市场下的无功电价研究

无功功率服务价格是电力工业重组中的一个重要的研究课题。由于传统的最优潮流数学模型不考虑无功功率的生产成本,因此无法得到合理的无功功率价格。文中在引入了无功功率的发电成本和无功补偿器的成本之后,运用最优潮流方法,分析了各种不同的优化目标及不同的约束条件对以经济学为基础的无功电价的影响及无功电价的特点。以一个实例系统对无功功率价格进行了研究,揭示了无功电价的一些基本规律,取得了有指导意义的成果。     

Congestion management with ex ante pricing for decentralized electricity markets

In this paper, the authors present a method and a model for managing transmission congestion based on ex ante congestion prices. Their method is influenced by the yield management approach widely used for airline reservation systems, and their model is built based on the relations between transmission congestion prices and electricity commodity prices that exist for an optimal solution. They formulate the congestion pricing problem as a master problem and the electricity commodity (energy and reserve) pricing as subproblems. Examples are presented to illustrate how a system operator can use this approach to compute ex ante congestion prices and how market operators can determine clearing prices and schedules of forward electric energy and reserve markets.     

Assessment of transmission congestion cost and locational marginal pricing in a competitive electricity market

In an open-access environment, transmission constraints can result in different energy prices throughout the network. These prices are, in fact, dependent on a number of factors such as the generating unit bid, system load level, network topology and security limits imposed on the transmission network due to thermal, and voltage and stability considerations. Computing these energy prices at all buses in large transmission networks under given system operating conditions can be time-consuming. This paper describes a simple methodology based on the analysis performed by the Hydro One in-house computer program (PROCOSE) to calculate, for a given period of time, transmission congestion cost (TCC) in dollars per unit time and locational marginal pricing (LMP) in dollars per megawatt-hour (MWh) at any selected bus in the transmission system. In addition, the information provided by the program output on congested transmission elements is used to identify buses in the network whose LMPs are representative of the entire network. The computed LMPs at these buses are used to define zones in the network where each zone has its LMP. The proposed methodology can be used to carry out sensitivity studies to determine the impact of changes in system parameters and operating conditions on the LMPs. The proposed method is illustrated using the IEEE Reliability Test System (RTS) and the Hydro One network system.     

Electricity transmission pricing: Tracing based point-of-connection tariff

Point-of-connection (POC) scheme of transmission pricing in decentralized markets charges the participants a single rate per MW depending on their point-of-connection. Use of grossly aggregated postage stamp rates as POC charges fails to provide appropriate price signals. The POC tariff based on distribution of network sunk costs by employing conventional tracing assures recovery of sunk costs based on extent of use of network by participants. However, the POC tariff by this method does not accommodate economically efficient price signals which correspond to marginal costs. On the other hand, the POC tariff, if made proportional to marginal costs alone, fails to account for sunk costs and extent of use of network. This paper overcomes these lacunae by combining the above stated desired objectives under the recently proposed optimal tracing framework. Since, real power tracing problem is amenable to multiple solutions, it is formulated as linearly constrained optimization problem. By employing this methodology, consideration of extent of network use and sunk cost recovery are guaranteed, while objective function is designed such that the spatial pattern of price signals closely follows the pattern of scaled locational marginal prices. The methodology is tested on IEEE 30 bus system, wherein average power flow pattern is established by running various simulation states on congested and un-congested network conditions.     

A Model for Efficient Consumer Pricing Schemes in Electricity Markets

Suppliers in competitive electricity markets regularly respond to prices that change hour by hour or even more frequently, but most consumers respond to price changes on a very different time scale, i.e., they observe and respond to changes in price as reflected on their monthly bills. In this paper, we examine mixed complementarity programming models of equilibrium that can bridge the speed of response gap between suppliers and consumers yet adhere to the principle of marginal cost pricing of electricity. We develop a computable equilibrium model to estimate ex ante time-of-use (TOU) prices for a retail electricity market. It is intended that the proposed models would be useful 1) for jurisdictions (e.g., Ontario) where consumers' prices are regulated, but suppliers offer into a competitive market, 2) for forecasting forward prices in unregulated markets, and 3) in evaluation and welfare analysis of the policies regarding regulated TOU pricing compared to regulated single pricing     

Marginal transmission pricing and supplemental cost allocation method: A case of Philippines

The paper presents application of marginal cost-based pricing of transmission services which is based on the use of bus incremental cost, in a real network of Philippines, and investigates the relationship between marginal network revenue and the transmission utility's (Transco) revenue requirement. The network income derived from marginal cost pricing fell below Transco's revenue requirement thus necessitating for supplementary charges. The paper proposes an allocation method that allocates supplementary charges based on the user's contribution to incremental flow. This method is applied to allocate the remaining network costs not covered under marginal pricing, and the results are compared with the traditional postage stamp method.     

Ex Post Pricing in the Co-Optimized Energy and Reserve Market

This paper discusses an alternative to the ex post pricing model currently under development within ISO New England's (ISO NE) ancillary service market. Since ISO NE's real-time ancillary service market co-optimizes both energy and reserve products, ex post pricing is needed for both energy and reserve. A co-optimization approach for ex post pricing requires defining complex pricing rules and implementing heuristics to ensure consistent binding constraints with the ex ante dispatch. In order to avoid complexity and uncertainty of required heuristics, a new ex post pricing schema is proposed to calculate the ex post energy and reserve prices in a decoupled way while recognizing the coupling effect of energy and reserve. In the proposed approach, ex post energy prices are first computed by incorporating the ex ante marginal opportunity cost of reserve in the energy offer; the ex post reserve prices are then calculated by considering the ex post marginal opportunity cost of energy. This approach simplifies the implementation of ex post pricing rules in the ISO NE market. Numerical examples are presented to further demonstrate the validity of this approach     

Power flow based monetary flow method for electricity transmission and wheeling pricing

This paper proposes a transmission and wheeling pricing method based on the monetary flow tracing along power flow paths: the monetary flow–monetary path method. Active and reactive power flows are converted into monetary flows by using nodal prices. The method introduces a uniform measurement for transmission service usages by active and reactive powers. Because monetary flows are related to the nodal prices, the impacts of generators and loads on operation constraints and the interactive impacts between active and reactive powers can be considered. Total transmission service cost is separated into more practical line-related costs and system-wide cost, and can be flexibly distributed between generators and loads. The method is able to reconcile transmission service cost fairly and to optimize transmission system operation and development. The case study on the IEEE 30 bus test system shows that the proposed pricing method is effective in creating economic signals towards the efficient use and operation of the transmission system.     

Long-run marginal cost based pricing of interconnected system wheeling

Each utility in an interconnected system has an obligation to guarantee sufficient transmission capability to maintain an efficient, economical, reliable and secure system during peak scenarios. Security is an important consideration underlying network investment. The standards of service have a direct impact on investment burdens and therefore definition and consensus among participants in respect of security standards are necessary. Charging for transmission services, ensuring the investment levels and recovery of sunk capital are new problems now receiving attention in the context of electricity supply industry unbundling. In this paper a method for long run marginal cost (LRMC) based pricing in multi-area interconnected system, based on the incremental use of each area's transmission network at times of peak flow, is proposed. The LRMC of transmission capacity is based on long term costs of transmission investment requirements. The marginal wheeling costs, with security taking into account, are computed using the sensitivities of the MW-mile of each area with respect to the bus power demand. These sensitivities are calculated using a linear expansion of the Kuhn–Tucker conditions of the investment cost optimization problem. Contingency ranking method is used to speed up the computation.     

Marginal cost of transmission system adequacy for spot pricing

A model of marginal adequacy costs is developed in order to reflect the influence that any nodal load has on system static security. An adequacy cost function is defined, making use of the load that must be theoretically withdrawn at each node in order to re-establish power flows on transmission elements, after any static contingency of a predefined set occurs. A minimal adequacy transport system is defined as a primary system used as reference for adequacy calculation purposes. Inclusion of adequacy cost function leads to co-ordination equations, which permit identification of marginal costs that are suitable for partial transmission equipment investment recovery. Results of simulations on the reliability test system (RTS) show important costs' components, which are variable in time and space, thus being appropriate for spot pricing schemes. It is verified that a significant part of transmission investment can be recovered by means of the marginal costs of adequacy.     

Reserve procurement and transmission capacity reservation in the Northern European power market

This paper provides the modeling approach and the associated results of determination of bidding prices for frequency restoration reserves (FRR) provision, and implications of cross-border transmission capacity reservation for FRR exchange. A model with three optimization blocks is developed. The FRR bidding price determination block uses an opportunity cost based approach to calculate the cost of providing FRR. For the FRR procurement, the transmission system operator (TSO) selects the cheapest bids with the possibility of cross-border exchange if transmission capacity is reserved for this purpose. In the day-ahead procurement block, optimal unit commitment and dispatch is determined, taking into account the reserve and transmission capacity allocations.A case study is done for the Northern European power system, consisting of the Nordic countries, Germany and the Netherlands. The results show how, among others, the FRR bidding prices are determined by the difference between the daily averaged sport price forecasts and the units’ marginal costs. The day-ahead and total reserve procurement costs are positively and negatively correlated to the system load respectively. As could be expected, costs are reduced in the FRR market when transmission capacity is reserved for this purpose. But a decrease in cost in the day-ahead market was also obtained for small transmission capacity reservations, caused by the increased flexibility in the FRR importing market. The total costs are the lowest for a transmission capacity reservation level of around 20%, illustrating that such reservation can be beneficial.     

FTR-option formulation and pricing

Recent changes in electricity markets have advocated the use of Local Marginal Prices (LMP) for congestion management and pricing. From the perspective of market participants, the LMPs pose a risk since they are not known before a transaction on the grid is made. Financial transmission rights (FTR) are instruments that help market participants hedge this risk and are issuable in two flavors—obligations and options. While pricing obligations are much easier, pricing FTR options pose a significant challenge. In this paper we develop a computational method for pricing FTR options. We also discuss the problem of designing financial instrument sets that assure revenue adequacy for the issuer. We point out the difficulty in assuring revenue adequacy when FTR options are present and propose a scheme for overcoming the difficulty. The proposed pricing method can be used to compute prices of options and obligations in the primary market or as a reliable pricing tool to compute option prices in the secondary market. Finally using a test network we present and discuss numerical results.     

Security of supply in electricity markets: Improving cost efficiency of supplying security and possible welfare gains

In liberalised markets the ability to maintain security of electricity supply is questioned because security is characterised as a public good. We discuss if this property can be modified with changing technology. Furthermore, we examine if construction of markets for security can be justified by possible welfare gains. From a welfare perspective it is possible that security levels are too high and obtained with too high costs. Adjusting the effort so that marginal cost for securing supply is at similar levels in generation capacity and in network maintenance could increase welfare even without the need to construct markets. Secondarily, a consumer defined average level of security might improve welfare. Finally, different willingness to pay among customers and construction of advanced markets might increase welfare further. We argue that several cost and welfare improvements can be achieved without constructing complete markets for security.     

New models for integrated short-term forward electricity markets

In a typical short-term forward wholesale electricity market where products are auctioned sequentially, one often observes significant market inefficiency and price volatility-thus the growing impetus in developing integrated short-term forward markets where electric energy, reserves, and transmission capacity are auctioned simultaneously. Such markets need new computational methods and models for determining market clearing prices and physical (delivery/consumption) schedules. The purpose of this paper is to examine key aspects of current modeling and pricing methods in short-term forward wholesale electricity markets and to introduce new models suitable for clearing price-based markets of integrated trades of energy, reserve, and transmission. Specifically, an analysis of the impacts of various pricing rules and bidding requirements on market operations is presented, the selection of optimization objectives is discussed, and a new model of transmission congestion and multiproducts simultaneous auction is introduced. Examples are used where appropriate.     

Analysis of a monthly auction for financial transmission rights and flow-gate rights

A monthly transmission rights (TR) auction issuing both point-to-point financial transmission rights (FTRs) and flow-gate rights (FGRs) is studied in this paper. Initially, a locational marginal pricing (LMP) based energy market is presented, in which the linear security constrained optimal power flow (SCOPF) problem is solved for each hour of system operation, determining the nodal prices, the transmission link capacity prices and the transmission congestion charges (TCCs) that should be collected by the ISO in case of congestion. A monthly auction is conducted in the TR market issuing FTR obligations, FTR options and FGRs to market players, building a link between all types of transmission rights under the same market structure. Combining the advantages of financial and physical rights, the market efficiency can be enhanced by offering a variety of choices for risk management to market players. The monthly TR auction is tested on several case studies using the IEEE three-area RTS96 and useful conclusions are drawn concerning the utility of the various types of transmission rights as compared to one another, in terms of the reimbursement they provide to their holders.