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Foreword for the Special Section on Electricity Markets Operations
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LECTRICITY markets have matured during nearly two decades of operation worldwide. Since the introduction of unbundled generation markets, both technology and the regulatory landscape have significantly evolved. Modern power systems are changing to accommodate smart grid technologies, such as distributed generation, renewable energy resources, demand response, FACTS devices, and microgrids. System operators are facing unprecedented variability in system conditions and, therefore, significant increases in uncertainty. On the other hand, governments are trying to lower the carbon footprint by mandating very high penetration of wind, solar, and other renewable energy sources. These trends are changing the way power systems are operated and planned, and indeed the way electrical networks are structured. Systems need more flexibility to respond to sudden shifts in increasingly volatile net loads. To create incentives for all controllable resources to provide additional capabilities, new market mechanisms and market products have to be developed in an effort to ensure sufficient levels of flexibility. To be successful, market design must adapt to these new demands and technologies, and accommodate new ways of operation. While regional markets are maturing, the issue of market coordination (so-called seams issues) is still not resolved and perhaps in some ways has worsened. Interties are underutilized and sometimes uneconomically scheduled, affecting overall market efficiency. Incentives to build generation in the most efficient locations are dulled by the barriers between systems and the difficulty of building transmission. System operators worldwide are actively working on the designing market coordination algorithms; however, there is no well-established methodology for solving the problem, especially in LMP-based markets. Political divisions in Europe, South America, Southeast Asia, and elsewhere require careful consideration of interregional power exchanges as well. A major source of improved efficiencies in power system operations has been enhancements of algorithms and hardware. Due to improved computing power, mixed integer programming (MIP) has become the state of the art for clearing unit commitment-based markets. Moreover, an increasing number of implementations of real-time markets include “look-ahead” functions with commitment and multi-interval optimization. Although MIP allows the inclusion of far more complexities in market clearing processes than were possible a decade ago, the pricing of such markets is non-trivial in the face of the market’s many non-convexities. Indeed, there is no rigorous foundation for many of today’s practices, and the problem of pricing nonconvexities is still open. Ex-post pricing approach also requires more serious consideration. In addition, the increased penetration of renewables is continuing to significantly shift power flow and trading patterns. Recognizing the highly stochastic nature of the modern power systems, a new class of algorithms is being actively developed to Digital Object Identifier 10.1109/TPWRS.2013.2290816
account for highly volatile new patterns of generation and transmission flows. Stochastic and robust optimization algorithms are examples of methods being investigated to accommodate these complications and uncertainties. These methods are exceptionally complex, computationally demanding, and sometimes not tractable. However, the decision-making process is getting much more difficult and opaque to participants, and economically optimal decisions are often counterintuitive. Developing efficient mathematical models and numerical solutions that yield transparent and meaningful prices are fast moving research areas in the industry. The papers in this special section reflect the above changes and new trends covering different aspects of electricity markets. Although they only address a subset of the above issues, they represent significant advances for several particularly important problem areas. There are two groups of papers. The first includes four papers that address frequency regulation. Ela et al. [1], [2] lay out a set of general principles for designing markets for primary frequency response (PFR), and then present an application. They define PFR as the immediate, autonomous response of generation and demand to system frequency deviations. Although few markets have historically procured PFR through competitive processes, Ela et al. argue that the high value of this service, as well as the significant cost of providing it, mean that market mechanisms should be sought to incent its economic provision as well as the technological innovations. Their second paper uses case studies to show how PFR acquisition interacts with markets for other ancillary services as well as energy in co-optimization schemes. A simulation of a wind-heavy system shows the growing importance of PFR. Papalexopoulos [3] considers what might be called secondary frequency regulation, in particular those resources that are controlled by the operator on a time scale on the order of seconds. He points out that previous market mechanisms in the US only rewarded regulation capacity, and not the ability to closely follow automated operator (automatic generator control) instructions. US markets have switched in the last year to a “pay for performance” methodology for paying regulation, which provides revenue for movement of a resource and not just capacity. Papalexopuolos proposes an alternative compensation mechanism for accuracy and rapidity of response, and evaluates it in a case study. In the final paper in the regulation group, Havel [4] considers automated control of power exchanges between control areas on the frequency control time frame. Predictions of the expected area control error and its standard deviation are combined with information on available operating reserves to recommend the cost-minimizing means of balancing real-time power demands. A simulation of the Czech transmission system indicates the potential for significant cost savings for regulation energy. The second set of papers also includes four contributions, but these consider scheduling of energy and capacity in real-time
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and day-ahead markets. Biskas et al. [6], [7] propose and test a model for unit commitment and production scheduling for a large-scale multi-zonal system, which they propose for use in a hypothetical pan-European market. The model considers the standard constraints incorporated in European power exchanges and pools. These include 1) block offers/bids, linked block offers/bids, flexible hourly offers/bids, and convertible block offers in power exchanges; 2) unit technical/commitment constraints; 3) system operating constraints in power pools; and 4) between-zone transmission constraints, which are used in market-splitting procedures. Although European markets are sometimes claimed to be simpler than US-locational marginal pricing markets, it has been observed that in fact, the first set of constraints is in many ways more difficult to handle than the network constraints that drive LMP markets. The authors demonstrate the feasibility of their approach by applying it to a 42 bidding area representation of the EU market, including three power pools and 22 power exchanges. Turning to the next unit commitment paper, Morales-España et al. [7] address what might be called another type of “seams” problem—the handling of transitions from one scheduling interval (e.g., one hour) to another. At such times, markets commonly experience rapid fluctuations of generator output and shorter-term (e.g., 5 minute) prices as resources move from one scheduled level of energy output to the next. Morales-España et al. propose a scheduling model that assumes that energy output ramps smoothly from the midpoint of one interval to the midpoint of the next, arguing that this results in more realistic and economic schedules than assuming abrupt transitions between intervals. Their model co-optimizes energy and reserves and is compared head-to-head with a traditional unit commitment formulation for two case studies. In the final paper of this special section, Papavasiliou and Oren [8] also add complications to the standard unit commitment model, in their cases those of stochasticity and alternative formulations of demand management. The three demand formulations they consider include co-optimization by the system operator of demand with generation; submission of demand bids by consumers to the day-ahead market; and the coupling of renewable resources with deferrable loads. The authors demonstrate certain advantages of the third approach through an application of their stochastic unit commitment model to the western North America power system. In summary, the use of optimization in operating electricity markets has hugely expanded over the last decade. This is
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because of the rapidly improving capabilities of modern software and computers to achieve near-optimal solutions while considering complicating constraints, such as transmission limits, and multiple commodities, including not only energy by several types of ancillary services. These papers point the way to how the usefulness of optimization can be expanded further by more effective modeling of frequency regulation and day-ahead generator and demand scheduling. The particular problems that these papers address are only a small subset of possible market enhancements that should be considered and possibly adopted over the next few years. We are confident that with careful testing and experience, the industry will see continued cost reductions, reliability improvements, and enhanced sustainability as a result of research in market operations. BENJAMIN HOBBS Johns Hopkins University Baltimore, MD 21218 USA
[email protected] EUGENE LITVINOV ISO New England Holyoke, MA 01040 USA REFERENCES [1] E. Ela, V. Gevorgian, A. Tuohy, B. Kirby, M. Milligan, and M. O’Malley, “Market designs for the primary frequency response ancillary service—Part I: motivation and design,” IEEE Trans. Power Syst., this issue. [2] E. Ela, V. Gevorgian, A. Tuohy, B. Kirby, M. Milligan, and M. O’Malley, “Market designs for the primary frequency response ancillary service—Part II: Case studies,” IEEE Trans. Power Syst., this issue. [3] A. Papalexopoulos, “Performance-based pricing of frequency regulation in electricity markets,” IEEE Trans. Power Syst., this issue. [4] P. Havel, “Utilization of real-time balancing market for transmission system control under uncertainty,” IEEE Trans. Power Syst., this issue. [5] P. Biskas, D. I. Chatzigiannis, and A. G. Bakirtzis, “European electricity market integration with mixed market designs—Part I: Formulation,” IEEE Trans. Power Syst., this issue. [6] P. Biskas, D. I. Chatzigiannis, and A. G. Bakirtzis, “European electricity market integration with mixed market designs—Part II: Solution algorithm and case studies,” IEEE Trans. Power Syst., this issue. [7] G. Morales-Espana, A. Ramos, and J. García-González, “An MIP formulation for joint market-clearing of energy and reserves based on ramp scheduling,” IEEE Trans. Power Syst., this issue. [8] A. Papavasiliou and S. S. Oren, “Large-scale integration of deferrable demand and renewable energy sources,” IEEE Trans. Power Syst., this issue.
Benjamin F. Hobbs (F’07) received the Ph.D. degree in environmental systems engineering from Cornell University, Ithaca, NY, USA, in 1983. He is the Theodore K. and Kay W. Schad Professor in the Department of Geography and Environmental Engineering, Johns Hopkins University, Baltimore, MD, USA, and directs the JHU Environment, Energy, Sustainability & Health Institute. He chairs the Market Surveillance Committee of the California ISO.
Eugene Litvinov (F’13) received the B.S., M.S., and Ph.D. degrees in electrical engineering. He is a chief technologist at the ISO New England, Holyoke, MA, USA. He is responsible for advanced system and markets solutions, smart grid and technology strategy and is a lead of the Research and Development activities in the organization. He has more than 35 years of professional experience in the area of power system modeling, analysis and operation; electricity markets design, implementation and operation; and information technology. Dr. Litvinov is an editor of the IEEE TRANSACTIONS ON POWER SYSTEMS.
