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This paper develops a representation of the Northeastern U.S. bulk electric power system, with an emphasis on New York and New England. The representation has two parts: a 36-bus electrical model in PTI-23 format and market data in the form of generator bids and load demands. The market data are distilled from historical data on public web sites. Since the historical data are available on an hourly basis over many years, the representation is quite rich. In addition, this paper includes the mix of generation at each bus in the model so that generation cost (fuel and emissions) and unit commitment constraints can be deduced. The representation is intended to be a test-bed for formulating, simulating and analyzing the combined technical and economic objectives of the changing electric power industry. It is further intended to be a test-bed for comparing methods of simulating electric power systems and electricity markets operating under engineering constraints. It can, for example, be used for power flow, optimal power flow, reliability, market clearing, and other economic studies. The representation as described is intended only for steady-state equilibrium studies and does not account for inter-temporal effects such as unit commitment constraints. It can, however, be extended to account for those effects. Index Terms--Electric power test systems, electricity markets, engineering and economics of electric power systems, power systems economics.

This paper presents a novel model for optimization of investments in new power generation under uncertainty. The model can calculate optimal investment strategies under both centralized social welfare and decentralized profit objectives. The power market is represented with linear supply and demand curves. A stochastic dynamic programming algorithm is used to solve the investment problem, where uncertainty in demand is represented as a discrete Markov chain. The stochastic dynamic model allows us to evaluate investment projects in new base and peak load power generation as real options, and determine optimal timing of the investments. In a case study, we use the model to compare optimal investment strategies under centralized and decentralized decision making. A number of interesting results follow by varying the assumptions about market structure and price response on the demand side. Index Terms--Centralized and decentralized decision making, generation expansion planning, real options, restructured power systems, stochastic dynamic optimization.

Strictly engineering aspects of Available Transmission Capacity (ATC) are analyzed first. Non-linear network theory is used to provide several key conditions under which one could define a notion of Available Transmission Capacity (ATC) and specific novel algorithms for its evaluation. Next, the fundamental problem which prevents one from developing an economically efficient distributed transmission market based on the Available Transmission Capacity (ATC) is identified. It is suggested that for an electric power network of an arbitrary topology it is not possible to map the computed ATC onto its market value. All findings are illustrated using examples of small power systems.

This paper presents a systematic framework for pricing transmission and ancillary services in competitive power markets. This framework is based on the recovery of fixed and operating costs, and it meets the traditional revenue requirements. It is practical, feasible, easy to implement, and to regulate. It can be implemented with minimum transition cost. This network flow-dependent and non-discriminatory framework is based on the decomposition approach presented in Part I of this paper. This decomposition forms an essential part of the proposed framework for usage-based recovery of the fixed and operating costs. The transmission system related fixed cost component is recovered from all transactions based on percentage utilization of the transmission system equipment. The charge is based on the actual network power flows. The ancillary service charge for a given transaction can be computed as the sum of the costs incurred at secondary generation for compensating the imbalance caused by that specific transaction. The 'path providing' function of the transmission grid is viewed as a true monopolistic service, its pricing is cost based, and charge for its use is usage based; the generation based ancillary service supply can be made competitive, its pricing is market based, and charge for it is usage based. A global overview of the proposed pricing strategy is analyzed in the context of other alternatives, especially cost-based methods. A numerical example on a five-bus system is given to illustrate the use of this pricing strategy.

This paper presents derivations of basic formulae for computing the contributions of each economic transaction to the network power flows throughout the system in steady-state operation of interconnected electric power systems. It is shown that the net system power imbalance caused by each transaction can be obtained as a function of all transactions present on the system. In addition, formulae are proposed for calculating the contributions of every ancillary generation unit to each transaction. This generation is needed to balance the system in response to economic transactions. Formulae supporting this are based on reformulating the load flow problem in terms of distributed slack bus.

A vector space is used to represent periodic voltage and current signals in a single port electrical network. This representation is convenient for expressing time average power quantities, such as average power, apparent power, and certain definitions of reactive power. The vector representation for reactive power provides insight into the difficulty of finding a consistent definition for a scalar measure of reactive power when harmonics are present. Instead, a reactive power vector is defined and shown to obey conservation according to Tellegen's theorem. Projections of the reactive power vector are shown to obey conservation and can be used as signed, scalar measures of reactive power.

This paper describes recent work on the theoretical and algorithmic enhancements of the MIT method for steady state voltage monitoring and control. Under the conditions that no dynamic voltage problems are present, the method is intended primarily to monitor steady state voltage and reactive power conditions, to identify potential problem situations, and to make decisions regarding their severity. The developed method utilizes various reactive power resources on the system to remedy voltage violations. The corrective actions suggested are either in the order assigned by the operator or according to efficiency criteria, determined by this algorithm. The corrective actions ensure minimum possible voltage deviations from a given desired voltage profile. Corrective actions are considered to be optimal in this sense. The method has the unique feature of identifying minimum number of most effective corrective actions so that voltages are maintained within the given limits. The method does not solve the exact load flow equations, and therefore it avoids inversion of a full system size matrix. Reactive power scheduling is computed so that the resulting load voltages are within pre-specified target values. The computational time does not increase significantly with increase of system size, since no inversion of a system size matrix is needed. Numerical tests on a small and large scale electric power system (IEEE 39 & New England 1726) are presented and analyzed.

In this paper the basic role of a secondary (regional level) voltage control in a multi-regional electric power system is reviewed. Specifically, certain limitations of presently implemented control schemes are described. Next an Improved Secondary Voltage Control (ISVC) scheme is proposed. In the second part of the paper possible enhancements of a multi-regional system operation by means of scheduled, Tertiary Voltage Control (TVC) interactions are proposed. It is shown that the prime role of a TVC is in managing limits on voltage control devices, such as generators. The theoretical developments are illustrated on two regions of the French electric power network.

The objective of this paper is to examine the theoretical bases for benefit optimization in centralized and decentralized electric power systems. In a centralized (single control) power system, we use cost, revenue, and profit as system performance criteria for benefit optimization, and compare the conditions. The results show that conventional cost minimization is not necessarily equivalent to benefit optimization based on other criteria. In a decentralized (multi-utility) power system, we investigate benefit optimization and its allocation at the unconstrained economic optimum, economic optimum with constraints, and conditions under which the solution is an economic suboptimum. We use the data from the EPRI Regional Systems to show practical examples of the benefit allocation with wheeling transactions. Although some rules are better for society than others, there still is not one right answer to determine the rules for benefit optimization.

This paper defines a price-based decision making process for participating in a reserve market for power systems reliability. Reserve power is a fundamentally different commodity from spot market power. It is suggested that depending on the payment mechanism in place, two different types of formulae would be used by power producers and users when participating in such markets. The paper points out that despite the imminent trend to create reserve markets, several fundamental questions concerning reliable operation must be studied. Index Terms--Deregulation, Industry, Reserve, Transmission Congestion, unit commitment.

This paper reports results of a joint industry-university study regarding possible steady-state voltage problems in portions of New England. Circumstances under which these problems may occur are described first; this is followed by a review of the operating and planning practices for preventing their occurrence. These engineering practices are compared with an analytic approach whose application to the same operating problems is presented in this paper. The results represent a verification of the method's potential to serve as a powerful tool for predicting steady-state voltage problems created by contingencies and for determining locations and amounts of available reactive power compensation and generation-based voltage support necessary to bring load voltages close to their pre-contingency values. The method is potentially useful for automating search for solutions under the operating conditions not previously experienced by a human operator and could be used as a basis for on-line steady-state voltage regulation. This is an important qualitative improvement over the presently practiced open-loop scheduling for preventing steady-state voltage problems. Keywords: Power system control, Power system monitoring, Power system planning, Power system stability, Reactive power control, Industrial power system reliability, Voltage control, Load flow analysis.