Judith B. Cardell

Market power and strategic interaction in electricity networks

Abstract Special conditions in electric networks complicate the analysis of the geographic scope of the horizontal market power. Unlike the conventional setting where a firm exercises market power by restricting its own production, there could be situations in constraining electrical networks where a generator would exercise market power by increasing its production in order to block transmission of a disproportionate amount of competing generation. A model with a set of Cournot firms, a collection of competitive fringe participants and an explicit representation of the electrical network illustrates the possible strategic interactions.

Reducing the Variability of Wind Power Generation for Participation in Day Ahead Electricity Markets

Uncertainty and variability in the wind resource create obstacles for the participation of wind power in forward markets, such as regional day ahead electricity markets. Studies performed in various states have developed methods to improve wind forecasting and so reduce the inherent uncertainty in a day ahead schedule for wind power generation. This paper addresses the issue of the variability in wind power generation by estimating the next ten-minute production level for a hypothetical wind farm, and then dispatching additional dedicated resources, such as responsive load or a gas turbine, in order to reduce the net variability of the generation in the next ten- minutes. Historical wind data from ISO-ne are used with an auto-regressive moving average model to develop the next ten-minute forecast. Preliminary results estimate the capacity required for the dedicated resources to maintain the wind output within a specified percentage of the submitted day ahead schedule.

Power exchange for frequency control (PXFC)

This paper concerns markets for balancing power supply and demand in real-time. Two qualitatively different market mechanisms are of interest: (1) primary electricity market(s) for supplying anticipated demand, and (2) a frequency control market for ensuring that system frequency remains within prespecified limits as demand deviates in real-time from its anticipated pattern. We suggest that both types of markets are necessary for ensuring that frequency remains within its technically acceptable limits as power is provided competitively. In particular, we develop one possible structure of a power exchange for frequency control (PXFC) that ensures frequency quality in a general primary electricity market comprising both bilateral and spot sub-markets.

Marginal Loss Pricing for Hours With Transmission Congestion

Nodal electricity prices are designed to send efficient economic signals to market participants for operating and investment decisions. The inherent nonlinearity of transmission losses and the use of marginal loss pricing can obscure the intended economic information in the loss component of nodal prices. As one step in clarifying the determination of the marginal loss price component, this paper discusses the calculation of nodal electricity prices in lossy networks and presents a variety of accepted methods for determining marginal loss. This paper then proposes a method for calculating the marginal loss component of nodal prices during hours with congestion that reflects each market participants contribution to marginal losses more accurately than current implementations. The proposed method recognizes that increases in incremental energy flows cannot flow across constrained lines, and thus, system-wide marginal losses should not be attributed to generators or loads in the constrained subregions. The objectives of the discussion are to improve the understanding of how marginal losses are determined and also to improve the accuracy of the information conveyed in the marginal loss price component. The ultimate goal is to promote more efficient price signals to electricity market participants for both transmission loss and congestion.

Wind power in New England: modeling and analysis of nondispatchable renewable energy technologies

Nondispatchable renewable energy technologies have beneficial environmental, financial and planning characteristics, yet are not readily included in resource planning analysis for two main reasons: the lack of familiarity in the power sector with their behavior, and the lack of appropriate analysis tools. This paper presents a methodology, to be used in conjunction with a standard production-costing model, for analyzing nondispatchable renewable energy technologies (RETs) as part of power systems operation. Our analysis of 1500 MW/sub p/ of wind power in New England shows that this capacity can capture the same amount of energy as the regions utility sponsored DSM programs, and that the wind resource in New England is comparable, on an energy basis, to that in California.

A Flexible Dispatch Margin for Wind Integration

Integrating wind power into power systems contributes to existing variability in system operations. Current methods to mitigate this variability and uncertainty focus on using conventional generator ramping capability. There is also the option of using wind power itself to mitigate the variability and uncertainty that it introduces into the system. This paper introduces the concept of a flexible dispatch margin as a means for wind to participate in mitigating net variability and net uncertainty. In providing a flexible dispatch margin, wind generators under-schedule in the hour-ahead energy market in order to have additional expected flexibility available for the real-time market. The implementation of the flexible dispatch margin is analyzed in a two-stage optimization model with recourse to the flexible dispatch margin, flexible demand and generator ramping. This modeling framework combines Monte Carlo simulations with AC OPF analysis, using the IEEE 39-bus test system. Results show that use of the flexible dispatch margin decreases the reliance on peaking generators to mitigate net variability and uncertainty, and also decreases the frequency of price spike events, particularly as wind penetration increases from 10% to 30%. The analysis emphasizes the importance of increasing flexible resource capability as power system variability and uncertainty increase.

The Control and Operation of Distributed Generation in a Competitive Electric Market

Small scale power generating technologies, such as gas turbines, small hydro turbines, photovoltaics, wind turbines and fuel cells, are gradually replacing conventional generating technologies in various applications, in the electric power system. These distributed technologies have many benefits, such as high fuel efficiency, short construction lead time, modular installation, and low capital expense, which all contribute to their growing popularity. The prospect of independent ownership for distributed and other new generators, as encouraged by the current deregulation of the generation sector, further broadens their appeal. In addition, the industry restructuring process is moving the power sector in general away from the traditional vertical integration and cost-based regulation and toward increased exposure to market forces. Competitive structures for generation and alternative regulatory structures for transmission and distribution are emerging from this restructuring process.

Distributed Resource Participation in Local Balancing Energy Markets

In response to the new and potentially conflicting economic and technical demands of independent, distributed resources, the power system requires a new means for coordinating system and market operations. Price signals are one mechanism available to coordinate the operation of a power system in the emerging competitive markets. This paper discusses the integration of distributed resources into the operations of the power system by means of organizing the resources into microgrids and allowing them to participate in local electricity markets through responding to price signals. The simulations of price signals proposed in this paper successively expand upon the current open loop market framework. For distributed resources to participate in energy markets and provide energy balancing two new price mechanisms are introduced and analyzed. First, an open loop strategy is introduced, based upon the concept of a proposed price-droop. Second, a closed loop strategy using a hypothesized dynamic cost equation is introduced. The behavior of distributed resources responding to these two proposed mechanisms is compared to their behavior in a strictly competitive environment.

Analysis of the System Costs of Wind Variability Through Monte Carlo Simulation

Wind power forecast uncertainty raises concerns of the impact of wind power on power system and electricity market operations. The analysis presented in this paper uses an optimal power flow (OPF) model in a Monte Carlo Simulation (MCS) framework to estimate the cost impacts from the uncertainty in windfarm output. Using various regional load levels, and assumptions on the costs for providing balancing energy, the results from the OPF and MCS show that wind power forecast uncertainty for the test system can increase production cost up to 350 times, though for most cases the forecast uncertainty does not introduce significant changes from the base cases. The real and reactive power losses are shown to be higher for scenarios with low wind-high load and high wind-low load as compared to the moderate wind-load cases.

Improved Marginal Loss Calculations During Hours of Transmission Congestion

Shortcomings of the current policy focus and accepted implementations for calculating and settling transmission losses strictly as marginal losses are presented. One modified marginal loss calculation approach for hours of transmission congestion is proposed and demonstrated using a 5-bus model from the PJM system. The objective of the suggested change in the use and determination of marginal losses is both to improve market transparency through an increased understanding of marginal loss calculations, and to improve the accuracy of the marginal loss calculation during hours with binding transmission constraints. Along with an ability to hedge risks associated with losses, these changes will lead to better defined market rules and property rights in electricity markets.