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Texas electricity market saw a recent integration of electricity transmission as a part of Competitive Renewable Energy Zones (CREZ). Exploiting the commissioning date of CREZ based transmission integration as an exogenous shock, we analyze the effect of transmission expansion on market clearing prices of Congestion Revenue Rights (CRR). Reduced form estimates suggest that excess transmission led to a lowering of CRR prices for contracts at all Times of Use. We find strong evidence of spatial, distributional, and firm specific heterogeneity. The paper shows that transmission expansion enhanced efficiency of the CRR market in terms of a spatial convergence in prices and a decrease in aggregate auction expenditure of approximately $260 million over a period of 4.5 years post CREZ. Keywords: Congestion Revenue Rights, CREZ, Market Integration, Transmission Expansion, 1. INTRODUCTION Texas electricity market is marked by a substantial wind energy penetration that accounted for about 17 percent of energy use in 2017, (1) up from 9 percent in [...]

Electricity tariffs typically charge residential users a volumetric rate that covers the bulk of energy, transmission, and distribution costs. The resulting prices, charged per unit of electricity consumed, do not reflect marginal costs and vary little across time and space. The emergence of distributed energy resources--such as solar photovoltaics and energy storage--has sparked interest among regulators and utilities in reforming electricity tariffs to enable more efficient utilization of these resources. The economic pressure to redesign electricity rates is countered by concerns of how more efficient rate structures might impact different socioeconomic groups. We analyze the bill impacts of alternative rate plans using interval metering data for more than 100,000 customers in the Chicago, Illinois area. We combine these data with granular Census data to assess the incidence of bill changes across different socioeconomic groups. We find that low-income customers would face bill increases on average in a transition to more economically efficient electricity tariffs. However, we demonstrate that simple changes to fixed charges in two-part tariffs can mitigate these disparities while preserving all, or the vast majority, of the efficiency gains. These designs rely exclusively on observable information and could be replicated by utilities in many geographies across the U.S. Keywords: Tariff design, Socioeconomic status, Pricing, non-convex costs, 1. INTRODUCTION Residential electricity tariffs typically distort--and thus do not allow consumers to respond to--the marginal cost of energy consumption. Rates are typically constant across time and location, despite the [...]

A novel concept of the adaptive emergency transmission rates (ATR) is presented. Traditionally used discrete emergency rates developed for a fixed period of time are replaced by a continuous adaptive rate applicable for any interval of time after contingency. ATR permits increasing power transfer in normal states without degradation of system reliability by allowing the maximal safe loading of electrical facility post-contingency corresponding to the transmission loading relief available via real-time dispatch. The approach is applicable mainly to real-time operations and short term planning and allows to not only lowering the cost of the operation, but also increasing the consistency of the economic dispatch in terms of the operator's discretion. Index Terms--Adaptive, emergency rates, operations, power system security.

In market-based planning and operation, it is very useful to have the information of generation dispatch, congestion, and price as load increases. Therefore, it is beneficial to system planners if the congestion or locational marginal pricing (LMP) versus load is readily available. This can certainly be obtained by repetitively running an optimization model at different load levels. However, this approach is too brute-force to be practical. In this paper, an efficient algorithm is proposed to identify the new binding constraint and the new marginal unit set when the system load increases from the present load level. It addresses the challenge of step changes in generation dispatch when a generation or transmission limit becomes binding. The algorithm also gives the new sensitivity of the new marginal units. Therefore, the generation dispatch, congested lines, and LMP at a new critical load level (CLL) can be easily calculated. Test results are presented in matrix formulation to clearly demonstrate and verify the proposed algorithm. Since the proposed approach is based on linearized model, it should be particularly suitable for short-term planning or operation, although application to long-term planning is also possible. Index Terms--Congestion management, critical load level (CLL), energy markets, generation sensitivity, locational marginal pricing (LMP), optimal power flow (OPF), power markets.

In this paper, we continue to analyze optimal dispatch of generation and transmission topology to meet load as a mixed integer program (MIP) with binary variables representing the state of the transmission element (line or transformer). Previous research showed a 25% savings by dispatching the IEEE 118-bus test case. This paper is an extension of that work. It presents how changing the topology affects nodal prices, load payment, generation revenues, cost, and rents, congestion rents, and flowgate prices. Results indicate that changing the topology to cut costs typically results in lower load payments and higher generation rents for this network. Computational issues are also discussed. Index Terms--Mixed integer programming, power generation dispatch, power system economics, power transmission control, power transmission economics.

The locational marginal pricing (LMP)-based settlement results in a surplus collected by the system operator from the consumers. The nonlinear transmission losses and the constrained operation of the power system due to operating limits, such as power flow limits on transmission lines, cause the accumulation of this surplus. This accumulated revenue, referred to as the network rental in this paper, has two main components: loss rental and constraint rental. This paper develops a method to calculate these different rental components paid by each consumer, by combining the power flow tracing and KKT optimality conditions. This yields quantitative determination of how each consumer has overpaid in the form of loss rental and constraint rental, which in turn can be used to get a better insight of how the rental is accumulated. Simple three-and four-bus systems are used to demonstrate the proposed method. Index Terms--Independent system operator, locational marginal price, network rental, optimal power flow program.

Practical models of competition among power generators who possess market power have generally had to use simplified models of transmission costs and constraints in order to be tractable. In particular, the linearized dc load flow model has been popular in complementarity and other types of oligopoly models. In this paper, we show how such models can be generalized to include quadratic losses, controilable DC lines, and phase shifting transformers. These generalizations preserve convexity of the feasible region, a property that facilitates computation and proof of solution uniqueness and existence. Piecewise and successive linearization formulations are also provided that allow consideration of nonlinear losses in models that require linear constraints. A simple six-bus example illustrates the application of these generalizations. In that example, the impact of losses on prices is much greater under strategic behavior than under competition. Large-scale applications of these approaches to markets in western North America and the European Union illustrate how inclusion of nonlinear losses and controllable DC lines can affect estimates of prices, flows, and economic efficiency indices resulting from oligopoly models. Index Terms--Economics, optimization methods, power generation, power transmission economics.

This paper analyzes the implementability of locational marginal price (LMP) and financial transmission right (FTR) mechanisms in the presence of high voltage dc (HVDC) lines in the regulated (i.e., under the control of system operator) network. The established framework of LMP-FTR mechanism assumes that the system under regulation is fully ac. Unregulated (or private) HVDC lines are taken into account within this framework through proxy-transaction bids from the line owners. However, as the flow over a regulated HVDC line has to be controlled by the system operator himself, the existing LMP-FTR framework becomes insufficient if the system contains or is expanded with regulated HVDC lines. The augmentation that should be made to the existing framework to include regulated HVDC lines is explained in this paper. It is shown that the flow over a regulated HVDC line can be modeled as a non-chargeable bilateral transaction without causing any threat of negative congestion surplus. For this power dispatch model, revenue adequacy of FTRs can be still ensured by means of the conventional simultaneous feasibility test (SFT) model. By utilizing the capacities of dc lines, a more general SFT model is further developed. The modified auction problem is discussed and tested for the non-negativity of net auction collection. The process of revenue adequate issuance of auction revenue rights is explained. Finally, the relative merit of a regulated HVDC line over a private HVDC line is discussed through a case study. Index Terms--Congestion management, financial transmission right, high voltage dc transmission, locational marginal price.

Deregulated electricity markets in the U.S. currently use an auction mechanism that minimizes total supply bid costs to select bids and their levels. Payments are then settled based on market-clearingprices. Under this setup, the consumer payments could be significantly higher than the minimized bid costs obtained from auctions. This gives rise to 'payment cost minimization,' an alternative auction mechanism that minimizes consumer payments. We previously presented an augmented Lagrangian and surrogate optimization framework to solve payment cost minimization problems without considering transmission. This paper extends that approach to incorporate transmission capacity constraints. The consideration of transmission constraints complicates the problem by entailing power flow and introducing locational marginal orices (LMPs). DC power flow is used for simplicity and LMPs are defined by 'economic dispatch' for the selected supply bids. To characterize LMPs that appear in the payment cost objective function, Karush-Kuhn-Tucker (KKT) conditions of economic dispatch are established and embedded as constraints. The reformulated problem is difficult in view of the complex role of LMPs and the violation of constraint qualifications caused by the complementarity constraints of KKT conditions. Our key idea is to extend the surrogate optimization framework and use a regularization technique. Specific methods to satisfy the 'surrogate optimization condition' in the presence of transmission capacity constraints are highlighted. Numerical testing results of small examples and the IEEE Reliability Test System with randomly generated supply bids demonstrate the quality, effectiveness, and scalability of the method. Index Terms--Deregulated electricity markets, electricity auctions, locational marginal price (LMP), mathematical programs with equilibrium constraints, payment cost minimization, surrogate optimization, transmission constraints.

Since deregulated power markets are very often oligopolistic ones, efficient models that are able to describe strategic behavior of firms must be developed. In particular, transmission constraints can easily increase the opportunities of market players to exercise market power. This paper presents a model that describes the firms strategic interaction, based on Nash-Cournot equilibrium, when the power network is taken into account. Specifically, this paper introduces a new iterative algorithm, that explicitly considers how the production at a certain bus affects the whole network, and consequently models the opportunities for the firms of exercising market power, taking into account their ability to influence the composition of the set of constrained lines. The theoretical basis of the method as well as a case study based on the Central European network is included. Index Terms--Game theory, interconnected power systems, oligopoly models, power system economics, transmission.

The residual demand derivative plays a central role in constructing the best response to competitors' strategies in widely used strategic models such as the Cournot model and the supply function model. In the absence of transportation or transmission constraints, the residual demand derivative is obtained straightforwardly by taking the derivative of the residual demand function with respect to price. However, in an electricity market, the market is embedded in a transmission network. When there is no transmission congestion, the residual demand derivative can be calculated as usual, but when there is transmission congestion, the residual demand derivative is more difficult to calculate. In this paper, we characterize the transmission-constrained residual demand derivative. We use the dc power flow model and characterize the residual demand derivative analytically. The residual demand derivative could also be obtained from the solution of a specific weighted least squares problem. Several properties of the residual demand derivative are implications of the weighted least squares theory. We also characterize the condition under which the residual demand derivative will be bounded or unbounded when there are perfectly elastic supplies/demands at some buses in the system. We verified our results in three examples: a two-bus system, a four-bus two-loop system, and a three-bus one-loop system with one perfectly elastic supply. The residual demand derivative characterization can be used to analyze the strategic behavior in both the Cournot model and the supply function model with transmission constraints, and it can be easily incorporated into sophisticated optimal strategy algorithms. Index Terms--Best response, Cournot model, electricity market, residual demand, supply function equilibrium, transmission constraint.

In this paper, a property rights model for electric transmission is proposed and its properties analyzed. The proposed rights, called 'border flow rights,' support financial hedging of transmission risk and merchant transmission expansion through associated financial rights, called 'contracts for differences of differences.' These financial rights allow for forward trading of both energy and transmission by a unified exchange, avoiding the bifurcation in current markets between decentralized long-term energy trading and centralized long-term transmission trading. Such long-term trading can help to support the financing of both generation and transmission assets. We consider incentive properties of such a right in the absence of lumpiness, economies of scale, and market power. Index Terms--Electricity market, energy and transmission trading, financial transmission rights, property rights, transmission investment.

This paper addresses the problem of allocating the cost of the transmission network to generators and demands. A physically-based network usage procedure is proposed. This procedure exhibits desirable apportioning properties and is easy to implement and understand. A case study based on the IEEE 24-bus system is used to illustrate the working of the proposed technique. Some relevant conclusions are finally drawn. Index Terms--Network usage, transmission cost allocation, [Z.sub.bus]

The expansion of transmission systems impacts many entities in the market environment. Each entity may fare better or worse as a result of congestion relief in the presence of new investments. Negatively affected firms exert their influence to prevent the expansion from taking place. The opposition of these firms and the lack of appropriate incentives results in insufficient investments in transmission assets. The network is being frequently used at its maximum limits, leading to economic inefficiencies and reduced reliability. Hence, there is a need for effective incentive schemes for network expansion. In this paper, we propose a game theory-based scheme for the allocation of transmission expansion costs among market entities. The allocation takes into account both the physical and economic impacts of the new transmission assets and the influence of each firm on the expansion decision. This is the first scheme designed to give all market participants explicit incentives to support the expansion. The application of the allocation solution to the Garver six-bus system is presented to illustrate the capabilities of the proposed method. Index Terms--Cooperative game theory, cost allocation, investment incentives, Shapley value, social welfare, transmission expansion.

A cost assignment model is proposed for the expansion of electrical transmission systems, based on the cooperation and interaction principles that are the foundation of the cooperative game theory. A solution algorithm is proposed that considers the development of independent cooperative games for each expansion segment and whose final assignment can be obtained by any game theory solution method (Kernel, Nucleolus, Shapley Value, etc.). The Kernel method was chosen because it has both equilibrium and transparency characteristics in the computation of final assignments. The model accepts both the technical (load nature, generation levels, etc.) and economic (power station marginal costs, etc.) variables that characterize the network to be analyzed. Cost assignment will depend both on the capacity economic use and the non-coincident maximum use of the expansion lines, made by individual and group agents. Index Terms--Cooperative game theory, Kernel, nucleolus, open access, shapley value, transmission cost allocation, transmission expansion.

ERCOT is an independent, not for profit organization that manages the deregulated electric system in the state of Texas. The deregulation model includes separate markets for bulk power and retail choice, with ERCOT acting as a facilitator for ancillary service market operation, reliability coordination and retail switching. The information technology (IT) tools are broadly classified under three categories--technical operations, commercial operations, and data warehouse. Technical operations include the market operation system (MOS) working in tandem with the power operation system (POS). Commercial operations include the client registration, load profiling, data acquisition, data aggregation, settlements, billing and a transaction clearing house. Since the ERCOT market is an evolving market, new market rules and reliability standards are established periodically and the IT tools are updated to reflect these changes. This paper provides an overview of the development and operational process of the IT tools pertaining to the ERCOT technical operations system. Index Terms--Ancillary service, balancing energy, day-ahead, deregulation, electricity markets, frequency control, ISO, market systems, real-time, RTO, state estimator.

This paper outlines the fundamental features of the PJM day-ahead energy market and real-time energy market. The Day-ahead market is based on a voluntary least-cost security constrained unit commitment and dispatch with several fundamental design features that ensure the market is robust and competitive. This market offers market participants the option to lock in energy and transportation charges at binding day-ahead prices. The flexibility of the day-ahead market rules provide all participants with equal access to the day-ahead market through consistent price signals and by providing all participants with the ability to submit virtual demand bids and virtual supply offers. These mechanisms promote liquidity in the markets. Economic incentives drive the convergence of the day-ahead and real-time market prices. The real-time energy market is based on security-constrained economic dispatch and is cleared based on the actual system operating conditions. The LMP-based markets support reliable grid operations through efficient price signals. Index Terms--Electricity market, locational marginal pricing.

The electricity industry of the Nordic countries went through a major restructuring during the 1990s. A wholesale market with significant competition has been established. Nord Pool was established in 1993 as a Norwegian electricity exchange, and extended its trade to Norway and Sweden in 1996. It thus became the world's first multinational exchange for trade in electric power contracts, and presently it is the only truly international electricity market. There is one market operator, and there are five system operators. Each country has its own regulatory agency. There are no general cross border tariffs. In 2001, power contracts worth nearly NOK 412 billion, about 55 billion Euro, were cleared by Nord Pool, and the combined volume of contracts traded was 2769 TWh, that is more than seven times the physical consumption. An open market with a common framework has made the Nordic market the most liquid electricity market in the world. Three of the countries have full retail market access. Since deregulation of the electricity industry started, restructuring has taken place in all countries resulting in mergers and acquisitions. There is an ongoing concentration of ownership in the wholesale market, and the concentration of the production side causes concern. Index Terms--Deregulation, electricity markets, power exchange.

The New Electricity Trading Arrangements (NETA) in England and Wales are just over one year old and are generally acknowledged to have successfully enabled competitive pressures to emerge fully in the generation market for the first time since the electricity industry was liberalised in 1990. With their emphasis on treating electricity as far as possible like any other tradable commodity and their lack of a centralized clearing market, they represent a radical departure from conventional wholesale trading arrangements. This article explains the principles underlying NETA and examines how the arrangements have fared over their first year. Index Terms--Competition policy, Energy market restructuring, Energy markets, Energy trading and risk management.

This tutorial paper discusses some aspects of electricity markets from the perspective of the demand-side. It argues that increasing the short-run price elasticity of the demand for electrical energy would improve the operation of these markets. It shows, however, that enhancing this elasticity is not an easy task. The tools that consumers and retailers of electrical energy need to participate more actively and effectively in electricity markets are discussed. The paper also describes how consumers of electricity can take part in the provision of power system security. Index Terms--Contracts, load management, load modeling, load shedding, power demand, power industry, power system economics, power system security.

This paper provides a state-of-the-art summary of risk assessment in energy trading. Techniques from financial engineering are needed by electric energy companies to manage price risk. These tools are needed by suppliers, distributors, and traders in a competitive electric power marketplace. Tools that have been adapted to the specific environment of the electric power system include portfolio analysis and hedging instruments. This paper provides a comprehensive critical literature survey of what has been applied to date in the power markets and which areas continue to need additional research. One example market scenario is used throughout the paper to demonstrate the usefulness of the risk assessment methods. Index Terms--Conditional Value-at-Risk (CVaR), electricity deregulation, energy trading, risk management, Value-at-Risk (VaR).

The deregulation of electric power industry, among other things, has created new requirements for participants in various electric energy markets and regions. In addition to the traditional power system monitoring, control, dispatch, analysis, optimization, and planning tools, the market participant requires tools to manage physical and financial assets, manage risk, participate in various markets, and decision support tools to provide the edge in a very competitive environment. The power system engineer, operator, and, in general, the market participant is being faced with requirements for which he does not have adequate training and proper background. In this paper, an attempt is made to provide an outline of the new requirements and to provide a footprint of some of the tools that are required to participate in the deregulated electric energy markets. Index Terms--Asset management, decision support, deregulation, electricity markets, energy, energy bidding, energy scheduling, energy trading, ISO, market participant, markets, portfolio optimization, risk management, RTO.

The market risks encountered by energy asset operators can be categorized as short term/operational, intermediate term/trading, and long term/valuation in nature. This paper describes how the market risks in operations can be measured and managed using real option models and stochastic optimization techniques. It then links these results to intermediate term value at risk and related risk metrics such as cash flow, earnings, and credit risk which can be used to measure trading risks over weeks to months; and how to optimize these portfolios for risk-return relationships. Finally, it then explores the risks in longer term energy portfolio management and how these can be simulated, measured, and optimized. Index Terms--Earnings at risk, energy risk management, portfolio optimization, potential credit exposure, real options, value at risk.

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 recent 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. Index Terms--Ancillary services, congestion management, deregulation, marginal cost, power markets.

Experience with deregulated electricity markets has shown that the assumption that markets will naturally produce competitive results is not justified. The existing independent system operators (ISOs) and emerging Regional Transmission Organizations (RTOs) all have developed or are developing systems and procedures to accomplish the monitoring task in their markets. This paper provides an overview of the key elements necessary for effective design and implementation of market monitoring systems Market monitoring must be concerned primarily with ensuring efficient market performance by identifying market inefficiencies, the potential for market abuses, and market power problems. In this paper, we define market power and identify factors that allow the exercise of market power in electricity markets. We also propose market efficiency objectives that should be used to design market rules that discourage gaming. We then identify the issues relevant to designing and implementing an effective market monitoring function. Index Terms--Market monitoring, market power, power industry, power transmission economics.

Under regulation, operating-reserve policy and investment policy are completely separate. In a market, they are tightly linked through expectations. Currently, regulators and engineers intervene in markets to determine how much will be paid when operating reserves are in short supply. These prices largely determine the revenue stream that pays the capital costs of new peakers and pays an equal amount toward the capital costs of all other generators. In this way, operating-reserve and price-cap policies determine investment in generation and the equilibrium level of installed capacity. Typically, FERC determines a price limit, and engineers, by setting an operating-reserve requirement, determine the expected duration of price spikes. Currently, these policies are set without coordination and without analysis of the long-run consequences. Index Terms--Installed capacity, investment, long-run market equilibrium, operating-reserve requirements, price spikes.

The evolution toward the standardized market design (SMD) is presented in this paper with references to the market developments in New Zealand, Australia, PJM, ISO-NE, and ERCOT. In the development of market designs, two main objectives--market liquidity facilitating bilateral trading and pricing efficiency facilitating congestion management, have been pursued. The efforts to balance the seemingly conflicting objectives led to most markets designed with a uniform or zonal pricing model. Introduction of locational marginal pricing and evolution of transmission rights from physical to financial form made it possible to harmonize the potentially conflicting goals in a market design. The close coupling between energy and ancillary services requires that markets for these commodities be carefully coordinated. Different operational practices and reliability standard requirements have led to major differences in ancillary service market designs. Index Terms--Ancillary service markets, electricity market, financial transmission rights, locational marginal pricing, standardized market design.

Under a common condition called profit suboptimality, market equilibrium cannot be reached in electricity pools; in other words, no system marginal price exists for which the profit-driven independent generators would self-schedule to levels that exactly meet the demand. On the other hand, although a centrally imposed generation schedule satisfies power balance, it may force some agents to operate at a profit below what they could achieve under self-scheduling. This paper examines these incompatible goals and proposes a conflict resolution scheme based on the notion of generalized uplift functions. These functions are defined such that they: i) change the offered generation cost characteristics so as to increase the system marginal price, thus forcing the consumers to compensate the generators for part of their combined loss of profit; ii) execute an equitable transfer of revenues among the generators so that these also participate in any loss of profit compensation; iii) ensure market equilibrium at the centralized minimum cost solution; iv) ensure that the net sum of the uplifts adds up to zero. Index Terms--Generalized uplifts, loss of profit, marginal pricing, market equilibrium, pool operation.

There are several issues in the deregulated markets that impinge on dispatching, pricing, and planning. It appears premature to desire a standard practice before resolution of such issues. This paper outlines the issues and debates possible remedies.

This paper compares methods for converting system limits into market signals. One classification of methods is according to reliability driven (TLR and similar) versus market driven (LMP and similar) methods. A second classification is according to direct versus indirect methods. Direct methods deal with individual limits and constraints. Indirect methods include various ways of converting one type of limit to another, equivalent limit for purposes of making the handling of the limit more expeditious. An example of an indirect method is the conversion of a voltage limit to either a flow limit or an interface limit. Another example is the use of flow limits on interfaces as surrogates for stability limits. These transformed limits are often represented by nomograms. Conversion of one type of limit to another and the construction of nomograms has the advantage of reducing the problem of imposing system limits within a market context to a 'previously solved' market problem. If a market already has learned how to cope with an import limit into a load pocket, conversion of a voltage limit into a load pocket import limit makes it easy for a market to react and respond to the condition. However, any conversion from one type of limit to another entails an approximation. This paper discusses the nature of some of these approximations. Index Terms--ATC, deregulation, flowgates, interface limits, LMP, locational marginal pricing, nomograms, stability limits, transfer limits, transmission limits, voltage limits.

In this paper, we provide a simulations-based demonstration of a hybrid electricity market that combines the distributed competitive advantages of decentralized markets with the system security guarantees of centralized markets. In this market, the transmission service provider (TSP) guides an electricity market toward the optimal power flow (OPF) solution, even when maximizing its own revenue. End users negotiate with each other to determine an energy price and then submit separate bids for transmission to the TSP. The TSP returns with prices for transmission, allowing end users to respond. In simulations, this hybrid-decentralized market approaches the near-optimal results of fully coordinated and constrained markets. Additionally, this market exhibits properties that remove incentives for the TSP to withhold capacity. This hybrid market leads a market toward the optimum while allowing the TSP and the end users to act out of self-interest. Index Terms--Coordination, decentralization, electricity markets, multilateral energy transactions, transmission markets, transmission pricing, transmission service providers.

Some of the various services provided under mixed pool/bilateral electricity trading are i) power to satisfy bilateral contract demand; ii) power for transmission losses and congestion management due to bilateral contracts; iii) power for transmission losses and congestion management due to wheeling contracts; and iv) power for transmission losses and congestion management due to pool demand. A procedure is developed and tested to unbundle these MW services as well as their corresponding costs, thus allowing the calculation of the average cost of each service. Comparison of the average and marginal costs serves to evaluate the relative profitability of each service. The goal of these results is to help generator and load-serving entities choose appropriate relative levels of pool versus bilateral trades while considering risk, economic performance, and physical constraints. Index Terms--Average and marginal costs, congestion management, cost unbundling, losses, pool/bilateral/wheeling markets.

This paper deals with the dispatch of power net works under mixed pool/bilateral trading. The major questions that are examined are the following: 1) To what degree does the relative level of pool versus bilateral trading influence performance in terms of individual power levels, costs, prices, and revenues? 2) What is the comparative performance of mixed trading with firm and nonfirm bilateral contracts under various curtailment strategies? 3) Is the revenue derived from the pool and bilateral trading consistent with the corresponding unbundled costs? The above questions are sequentially addressed in separate parts of this three-part paper. The eventual goal of these results is to help generator and load-serving entities choose appropriate relative levels of pool versus bilateral trades while considering risk, economic performance, and physical constraints. In Part H, two types of bilateral contracts, firm and nonfirm, are introduced together with their respective curtailment and noncurtailment bids. The optimal power-flow problem from Part I is now modified to accommodate this new type of operation. Technical and economical performance measures defined in Part I, namely, generation revenues from bilateral and pool sales, pool demand payments, plus generation and load expenditures to cover transmission loss and congestion management attributed to bilateral exchanges are also used here together with revenues from contract curtailment and expenditures due to noncurtailment bidding. Simulation results illustrate the effects of firm and nonfirm contracts and their bidding strategies on the relative levels of pool/bilateral trading, as well as on economic performance of market participants. Index Terms--Bilateral contracts, costs, curtailment and noncurtailment bidding strategies, firm and nonfirm contracts, incremental costs, mixed trading strategies, pool operation, prices, revenues.

In this paper, we present a systematic exposition of generator-provided reactive support as an unbundled ancillary service under open access transmission. We discuss the nature and salient physical characteristics of reactive support and analyze their implications in acquiring VAr support as one of the ancillary services. The paper provides an analysis of the dominant component in the cost structure of this service. This component is determined from the opportunity costs, which are evaluated from the foregone profits of a generator in making sales in real power markets by providing reactive support instead of real power. We illustrate the combined effects of the voltage set points of the generators and of the generator capability constraints on the transactions in competitive electricity markets, both under normal and contingency operating conditions. We discuss the key role of the grid operator in the provision of the reactive support, and the key considerations in the acquisition and pricing of the reactive support service. Index Terms--Ancillary services, electricity markets, opportunity costs, reactive support, transmission services, unbundling.

Among the ongoing liberalization of the global energy markets, several technical developments in the field of power electronic based transmission devices lead to a significant restructuring of the electric power supply. These FACTS-devices (Flexible AC Transmission Systems) enable a continuous and wear-resistant control of active and reactive power flows as well as voltage control. The incorporation of the control capabilities provided by FACTS-devices into an optimal power flow (OPF) opens up an unused potential for reducing power losses as well as cost for power transmission of the power system operator. This paper describes the optimization method basing on sequential quadratic programming (SQP) including models of FACTS-devices suitable for a gradient based optimization. Furthermore, the economically efficient operation of FACTS-devices is shown using different scenarios. Index Terms--FACTS, open access, optimal power flow (OPF), quadratic programming.

The paper describes how a small 50 MW combustion turbine peaking generating plant can make a dramatic improvement if its location is internally within a 2500 MW load area in a generation deficient system that has the potential for voltage collapse. In the era of open access transmission, the power market will always tend to import less expensive power, and load up the transmission system rather than support the generation of less-economic local power. This will use up available reactive power and will inevitably result in lower voltages. In an identified low voltage scenario, when a N-2 outage could cause a serious reliability situation that may threaten the region, reserve or peaking 'less economic' generation located internal to a load area has a vital part to play regardless of economics. Key Words: Power Transmission System, Voltage Collapse, Power System Dynamic Stability, Reactive Power, Load Shedding

A space power relay system (PRS) that uses advanced technologies to transmit power to different parts of the globe was investigated for its economic feasibility. Results showed that providing electric power via the PRS system is not an economically viable business when electricity prices are competitive to those in developed US cities because of a low internal rate of return (IRR). However, when the target market has prevalent electricity prices that are much higher, such as in Japan, the use of the PRS system can yield an IRR over 65%.

A method of calculating Available Transfer Capability and the exploration of the first order effects of certain power system network variables are described. The Federal Energy Regulatory Commission has ordered that hulk electrical control areas must provide to market participants a 'commercially viable' network transfer capability for the import, export, and through-put of energy. A practical method for deriving this transfer capability utilizing both linear and non-linear power flow analysis methods is developed that acknowledges both thermal and voltage system limitations. The Available Transfer Capability is the incremental transfer capability derived by the method reduced by margins. A procedure for quantifying the first order effect of network uncertainties such as load forecast error and simultaneous transfers on the calculated transfer capability of a power system snapshot are explored. The quantification of these network uncertainties can provide information necessary for system operation, planning, and energy market participation. Keywords: Electric Power Deregulation, Transmission Transfer Capability, network Uncertainty

This paper presents a new method for solving the unit commitment problem by simulation of a competitive market where power is traded through a power exchange (PX). Procedures for bidding and market clearing are described. The market clearing process handles the spinning reserve requirements and power balance simultaneously. The method is used on a standard unit commitment problem with minimum up/down times, start-up costs and spinning reserve requirement taken into account. Comparisons with solutions provided by Lagrangian relaxation, Genetic algorithms and Chao-an Li's Unit De-commitment procedure demonstrate the potential benefits of this new method. The motivation for this work was to design a competitive electricity market suitable for thermal generation scheduling. However, performance in simulations of the proposed market has been so good that it is presented here as a solving technique for the unit commitment problem. Keywords: Thermal units, power generation scheduling, free market, power exchange.