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An Overview of Ancillary Services in an Open Market Environment Igor Kuzle, Senior Member, IEEE, Darjan Bošnjak, Student Member, IEEE and Sejid Tešnjak, Senior Member, IEEE

Abstract – The worldwide restructuring of the electrical energy industry is followed by processes like deregulation, liberalization and commertialization. These changes introduce new paradigms such as competition in generation and the concept of electricity supply as a commodity market and creates a new set of transactions among utilities and new agents and end users. An important aspect is the role of competitive markets stressed by the new regulation in procurement and remuneration os ancillary services. These services are required to provide stability and security of supply. Ancillary services have a variety of terms used throught the world to name them (e.g. system services, support services) and it is not easy to define or classify them. The objective of this paper is to give a possible classification scheme for ancillary services to allow an easier identification of the roles of suppliers and buyers. Also, means by which the costs of various services can be measured, quantified and allocated are discussed and one method for cost allocation is proposed. Index Terms—Ancillary Services, Auman-Shapley Allocation, Deregulation, Electricity Market

Cost

organizationally-isolated generation business units. In order to provide security and stability of supply several tehnical services known as ancillary services are required These services can be economically contracted from a range of different IPPs. Such system offers competition and diversity in the provision of ancillary services and ensures Independent System Operator (ISO) with contracts for all the services which are needed. [1][2] The objective of ancillary services markets is a low cost reliable electricity supply in the long term. These markets should be made attractive towards the parties of electrical energy industry and attract investments in the strategic sectors of security of supply and the quality of electricity. An important issues in this new market enviroment are the choice of market rules and the adoption of the price setting mechanism that ensures recovering costs of devices supplying ancillary services. [3]

II. OVERVIEW OF THE ANCILLARY SERVICES

T

I. INTRODUCTION

HE electric power industry has over the years been dominated by large utilities that had an overall authority over all activities in generation, transmission and distribution of power within its domain of operation. Such utilities have been referred to as vertically integrated utilities, and these utilities served as the only electricity supplier in the country or region and were obliged to provide electrical power to everyone. Since the last decade of the 20th century, power utilities from around the world have been going through a process of restructuring in order to introduce commercial incentives in generation, transmission and distribution. These reforms include a clear separation between production and sale of electricity, and network operations. The erstwhile vertically integrated system operations regarding generation, transmission and distribution have been separated into independent activities. The generation companies sell energy through competitive long-term contracts with customers or by bidding for short-term energy supply at the spot market. In this new scenario, new generation is increasingly being built by independent power producers (IPPs) or by an

Ancillary services are those services necessary to support the transmission of electric power from producer to purchaser. These services are required to ensure that the system operators are able to meet their responsibilities, but also aim at enhancing system reliability and maintaining adequate quality standards. The ISO uses ancillary services for the following tasks: 1. Keeping the frequency of the system within certain bounds 2. Controlling the voltage profile of the system 3. Maintaining the stability of the system 4. Preventing overloads in the transmission system 5. Restoring the system or portions of the system after a blackout [4] There is no common classification of ancillary services in the world and even some similar services have different names in differenet countries. The European Directive 2003/54/EC concerning common rules for the internal market is a general framework and the Member States can define their own implementation details regarding the transition from monopoly to liberalized market. In the USA, FERC’s (Federal Energy Regulatory Commission) Directive 888 defines 12 tehnical and non-tehnical ancillary services. Six of those services are mandatory which means that transmission

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providers and customers are forced, respectively, to sell and buy them.[3] The main ancillary services are: Reactive power, Frequency control, Reserves, Load following, Black Start, Losses and Load shedding. A. Frequency Control Frequency regulation is the control of the system frequency by maintaining a balance between generation and load on a real-time basis within a control area. When a disturbance occurs in the system, there is an imbalance between the load and the generation and the system frequency dips. This frequency dip triggers an instantaneous increase in the system generation, initiated by the governor responses. This is commonly known as the primary regulation. Primary regulation must respond to changes within few seconds. The generation increase combined with the frequency-dependent load reduction will stabilize the system at a frequency that is slightly less than nominal. This will, however, cause unscheduled power flows on the tie lines and lead to undesirable accumulation of area control error (ACE). To return the system to the nominal frequency, the generation set point of some units must be re-adjusted. This is usually done through automatic generation control (AGC), but it can also be achieved through manual adjustment. This control action is reffered to as secondary regulation and it must respond to signals within 5 to 10 minutes. In theory, frequency control can be attained by sending appropriate price signals to generators and loads who voluntarily adjust their production or consumption based on this signals. In general, frequency control action can be provided anywhere in the system, but the transmission capabilities and limits must be taken into account to prevent congestions or overloading of transmission elements. [4] The benefits of frequency control include avoided costs of loss of industrial production, community disruption and inconvenience, equipment damage and market distortion. Many of these benefits are very difficult to assess because of the large number of people involved. Above all, frequency control is necessary to maintain power system security and, therefore, it has a commercial value. It is the result of a demand from customers to maintain electric energy security at an acceptable level. In vertically integrated utilities, the costs of providing frequency control are essentially the incremental costs of providing plant with frequency control capability, maintenance due to frequency control activity, holding generation capacity in reserve and possibly any benefits given to consumers for the ability to shed their load. These costs are difficult to quantify. A market for frequency control services may assist in the evaluation of these costs. However, in a market environment, prices are more reflective of business opportunity than the actual costs of service delivery. The traditional view that frequency should be controlled within a narrow range in the absence of contingency events is often challenged by the market costs of doing so. In some cases, probabilistic definition of frequency standards (e.g. keeping

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2 the frequency within a certain range for a certain percentage of time) may provide additional flexibility to achieve a more economic outcome. B. Reserves Reserves are designed to respond to uncertanties and needed for maintaining the integrity of the transmission system in the presence of disturbancies. Reserves are important both for energy and for reactive power. The two main disturbancies are generation outages and load variations. An arbitrary but widely accepted classification organizes reserve services into three time frames: Spinning reserves. Their time of response is from a few seconds to about 5 minutes. It is not necessary for spinning reserves to be able to deliver power for a long period of time since these are eventually displaced by the supplemental reserves Supplemental reserves. These reserves have the response time from several minutes to half an hour. Supplemental reserves are used for stabilizing the system frequency and energy balancing within a control area. After some prescribed time they are replaced by Backup reserves. These can sty in service for a longer period of time, but are not expected to come on line for some time (30 minutes or more). Frequency control, load following and reserves services are closely relates, but distinct services. Although the objective of reserves is the same as for frequency control and load following (maintaining a balance between supply and demand), the situations in which it is needed are different. Reserves are intended to deal primarily with outages and disturbancies. At some point, reserves are no longer an issue for an operator to be concerned about and become an issue for market to resolve. However, market must provide at all times the operator with an operable system under all foreseeable circumstances. The cost of providing the service depends on the requirements of the system. One of the most important principles for measuring and pricing reserve services has to do with opportunity costs. In general, a generating has three choices: staying off line (providing backup reserves), coming on line at less than maximum power (providing spinning reserve) and coming online at full power (not providing any reserve services). The best choice depends on generating unit’s efficiency. C. Load Following Regulation and load following are services classically provided by, and under the jurisdiction of, a control area to balance the measured mismatch between generation and load. Deviations in load from the scheduled value are normally supplied by some generating units under AGC or participating in manual frequency control. They are substantially the same service except for the time frame. While regulation should

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follow minute-to-minute load variations, load following addresses variations that occur over a longer time horizon. In some cases there is no real possibility of distinguishing between the two services. [6] One possibility in a deregulated electricity market is to establish a market with bilateral contracts. In this structure, each of the generators, if it satisfies tehnical conditions, would have a closed loop load following controller. A demand signal, that arrives directly from the load, is compared to the power output of the generator to yield a mismatch that is called Generator Control Error (GCE). GCE is some sort of a local Area Control Error (ACE). It is necessary to emphasize that such variation in the classic AGC model does not compromise the frequency control. Such a generator contributes, because of its speed droop feed-back loop, to the primary frequency regulation. It also can be under AGC and join the classic supplementary control while satisfying the bilateral contract at the same time. The demand signal must arrive directly from the load. This means that, to create a bilateral market, it is necessary to have a very well developed communication system with the possibility of monitoring customers. Choosing to purchase load following through bilateral contracts guarantees the advantage of having the generation strictly match all load variations. This is an important issue, speciallly for those loads which create large or fast real time power imbalances. At the present, on the contrary, there is no good reason for customer to be interested in such a market. The charges applied for services such as load following are still flat and there is no real distinction between users. Prices for load following are incorporated into tariffs which do not take into account the different burden imposed by each user on the system and do not compensate adequately the generator provider. As long as a new pricing scheme for AS is not developed, it is difficult for any kind of competitive market to be feasible. [6] D. Reactive Power This service is also reffered to as Voltage control. It’s purpose is controlling reactive power flows which is essential for a power system to operate within acceptable voltage limits. Reactive power flows can give rise to substantial voltage changes across the system, which means that it is necessary to maintain reactive power balances between sources of generation and points of demand on an area basis. At low loadings, capacitive effects dominate and voltages tend to increase (the Ferranti effect). At high loadings, inductive effects dominate and voltages tend to become depressed. The Surge Impedance Loading point is a point at which both effects cancel each other. [4][5] An essential property of reactive power is that “it does not travel far”. Unlike system frequency, which is consistent throughout the system, voltages across the system form a voltage profile and reactive power sources must be distributed all over the network. It is also necessary to maintain sufficient reactive reserves, both leading and lagging, to satisfy any

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3 changes in power system requirements. The loss of generators, transmission lines and reactive devices will change the overall reactive power requirements. Thus, reactive power reserves need to be strategically placed in order to respond effectively and maintain the system security. The tehnical characteristics of reactive power may prevent the development of a fully competitive reactive power market. In most situations there is a single supplier or buyer avaliable in some area and it has the potential of using market power. The value of one MVAr of reactive power is not the same everywhere in the system. Consequently, if a reactive power market is settled like a real power market, the ISO can end up contracting a set of low-priced offers from such locations (buses) that are undesireable from system considerations. Therefore reactive power markets need a new approach that takes into account both offer prices and location of the resource. Much of the reactive power provision is done by means of equipment that has a large investment cost but tends to have negligible operating marginal costs. Consequently, traditional methods for establishing a market do not apply because these rely on assumption that prices will approach the marginal cost of production. [4] The implementation of a reactive power service could theoretically be entirely market driven, but it’s usually underpinned by mandatory requirements which apply to all generating units. Mechanisms that have been used in contracting for reactive services include: • no payment • tariffs • bilateral contracts • tender markets The dynamic market approach is not usually applicable, as the locational significance of the reactive power service rarely results in the necessary conditions of surplus capacity being met. Consequently, the tender market approach is the economically most efficient mechanism available. Using such a mechanism requires careful planning. Total life cycle costs need to be minimized and contract periods are likely to be medium term. It is assumed that the reactive power market is monopsonistic in it’s structure, which means that there is only one buyer (ISO) present. It is therefore essential to have a mechanism, in terms of a financial incentive, that will force the ISO to act in the most economic manner, encouraging it to only incur minimum costs necessary for providing the appropriate level of security and quality. Regulatory authorities need to ensure that optimum volumes are purchased.[1][5] E. Black Start Black Start is the procedure to recover from a total or partial shutdown of the transmission system which has caused an extensive loss of supplies. In general, all power stations need an electrical supply to start up: under normal operation this supply would come from the transmission or distribution

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system. Under emergency conditions Black Start stations receive this electrical supply from small auxiliary generating plant located on-site (a small gas turbine or a diesel plant). Once running, a large generating unit can then be used to energize part of the local network and provide supplies for other stations within its area. It would not be efficient, either economically or technically, if all power stations were obliged to provide a Black Start service. Rather, the ISO looks to contract with generators that are perceived to be particularly effective in strategic areas on the system. A power station with a Black Start capability will want a revenue to recover the costs of making a Black Start facility available. A significant proportion of this income will consist of a Black Start availability payment. The Black Start plant may be installed solely to provide a Black Start service. Alternatively, it can also be used for other energy-related services such as peak lopping and standing reserve. In addition to the above “holding payments”, further payments are made when the service is utilized - both for testing purposes and in the event of a Black Start. The costs include capital costs, testing costs, training costs, equipment damage costs, and fuel plus labor costs during actual blackstart operations. Competitive markets could develop for blackstart capability. If there are enough generators located so that they can provide the blackstart service, the competition among them may be enough to allow markets to determine the prices of this service. The control-area operator is the only buyer because it is responsible for determining how much of the resources to acquire and how to deploy them. The systemcontrol and transmission portions of system blackstart cannot be provided competitively. [7][8]

transmission access agents equal the cost for the transmission system in acquiring the corresponding ancillary service. In addition it is also fair and economically efficient.

Fig. 1. Ancillary Service Providers

Suppose that two transmission agents A and B are going to use a resource together. Let PA, PB the amount of their transactions and c(PA, PB) the total cost in providing the resource as a function of PA, PB. Let us assume that the function c(x,y) is differentiable. The problem is how to split the cost between A and B. Economic efficiency can be induced by charging agents in proportion to their marginal use of the system (cost allocated to A is πAPA, and cost allocated to B is πBPB), where

πA =

∂c ∂c ( PA , PB ) ; π B = ( PA , PB ) ∂x ∂y

(1)

are marginal costs for a given transaction. The problem with this allocation rule is that if c(x,y) is derived from a decreasing return to scale production function, the revenues collected by the transmission system operator are greater than the cost of providing the service:

π A PA + π A PA > c ( PA , PB ) .

(2)

III. COST ALLOCATION OF ANCILLARY SERVICES Since ancillary services are essential to reliability, it is not always possible to obtain all ancillary services by market means. These services often have low marginal costs. Thus, it is common that market pricing the service at marginal cost pricing will not result in sufficient compensation to the providers of the service, and it will lead to lower reliability. In these cases, it becomes necessary to split the payments for the service into a market component and a cost-allocation component. While some AS can be purchased from markets, other services may be more effectively handled by the transmission entity alone. The cost incurred for acquiring these services is then shared among the transmission system users as illustrated in Figure 1. To promote economic efficiency in resource utilization cost allocation based on marginal cost is most desirable because it is compatible with a competitive economic environment. This section proposes a methodology of cost allocation for any ancillary service based on marginal costs using gametheoretic principles (Aumann-Shapley pricing). The methodology ensures that the total revenue collected from the

At first sight, the over-recovery can easily be corrected by applying a reduction factor, but it may not always lead to an efficient cost allocation [4]. Another way to solve the problem is by calculating the difference in service costs as agents A and B are successively added to the system. This approach is called incremental cost allocation. It eliminates revenue conciliation problem, but it is very sensitive to entrance order. The Shapley scheme tries to eliminate these limitations by calculating all permutations of entrance orders, but it is not neutral with respect to the size of similar agents. In Aumann-Shapley allocation, each transaction is portioned into a large number of small transactions of equal size. Let ∆ be the size of the small transactions. Then the original transaction of agent A, PA, would correspond to N1 transactions of equal size ∆, and PB would correspond to N2 transactions of equal size ∆. The Aumann-Shapley cost allocation formula can be obtained as a limiting process of the above scheme as the size of sub transactions ∆ goes to zero. The cost associated to c(PA, PB) for agents A and B is equal to

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TABLE I GENERATOR DISPATCH

π A =

∂c ∫t =0 ∂x ( tPA , tPB ) dt l

∂c

l

π B =

(3)

∫ ∂y ( tP , tP ) dt A

(4)

B

t =0

Because it is based on marginal costs, Aumann-Shapley method has the property of inducing economic efficiency. In addition, it is generally considered “fair” in the sense that it eliminates “order of entry” as a consideration. Another important property of Aumann-Shapley allocation is that it has the property of recovering cost. IV. APPLICATION OF AUMANN-SHAPLEY SCHEME TO THE REACTIVE POWER LOSS COST ALLOCATION The amount of active power losses depends on the active and reactive power dispatch. The transmission loss cost is defined by the difference between the amount paid to the generators in the transmission-constrained operating costs with and without losses. The least cost transmissionconstrained dispatch is the result of the following optimization problem: (5) z ( d ) = Min c' g

s.t.

g + P(v, Θ) = d Fl (v, Θ) ≤ Flm

(5b)

g≤g≤g

(5c)

v≤v≤v

(5d)

(5a)

Where:

z (d ) d g v Θ c’

total dispatch cost load vector active generation vector vector of bus voltage levels vector of bus voltage angles vector of generation costs

g, g

vector of min. and max. active generation

vector of min. and max. bus voltage levels The Aumann-Shapley unit cost associated to the loads is:

v, v

π diAS =

∂z (λd ) ∂λ ∂d i =0

1

∫ λ

It is also assumed that each load will pay

Bus # 1 2 7 13 15 16 18 21 22 23

Dispatch without losses 345.01 338.46 364.07 995.07 304.48 206.22 585.91 569.45 354.37 1066.76

Dispatch with Losses 381.02 380.99 400.07 1178.61 428.05 308.09 770.89 480.32 46.57 835.82 Total

MW Difference 36.01 42.53 36.00 183.54 123.56 101.87 184.98 -89.13 -307.81 -230.94 80.62

36.01 42.53 36.00 183.54 123.56 101.87 184.98 -89.13 -307.81 -230.94 80.62

Table 1 shows generator optimal dispatch for the lossless case and the case with losses. It is assumed that generation cost is linearly dependent of load. It can be seen that due to losses some generators decrease and some other increase their generations. TABLE II BUS MARGINAL COSTS Bus # 1 2 7 13 15 16 18 21 22 23

Marginal cost without losses 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

Marginal Cost with Losses 1.02 1.02 1.00 1.01 1.06 1.03 1.00 1.00 1.00 1.00

Loss Cost Marginal Cost 0.02 0.02 0.00 0.01 0.06 0.03 0.00 0.00 0.00 0.00 Total

Revenue Collected 3.17 2.83 0.01 6.93 21.6 4.65 0.97 0 0 0 230.39

Table 2 shows the marginal cost for two cases (with and without losses), their difference and the revenue collected for the loss cost based on marginal costs. The revenue collected for loss cost based on marginal charges (230.69) is much higher than the actual loss cost (80.62). Marginal costs with losses taken into account are much higher than the marginal costs without losses for all buses. The generation cost curve in Figure 2 is linear due to generator cost in all generation buses. The curve for the case with losses would also be almost linear because the amount of loss is small compared to system load. The loss cost curve in Figure 2 is convex which suggests an increasing marginal cost behavior. This explains the fact that the revenue collected for loss cost based on marginal charge is much higher than actual loss cost.

(6)

π diAS d i

Cost difference

and that

each generator will receive ci g i . It is possible to prove that the total amount received by the generators is equal to the total amount paid by the loads [2]. An application of Aumann-Shapley method is illustrated using 24 bus system, derived from the IEEE Reliability Test System.[2] Fig. 2. Generation cost without losses and loss costs

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TABLE III AUMANN-SHAPLEY GENERATION COST Bus # 1 2 7 13 15 16 18 21 22 23

AS cost without losses 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

AS Cost with Losses 1.00 1.00 1.00 1.00 1.01 1.01 1.00 1.00 1.00 1.00

[5]

AS Loss Cost

Revenue Collected

0.00 0.00 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.00 Total

0.11 0.09 0 0.45 3.71 1.27 0.04 0 0 0 83.62

Table 3 shows the Aumann-Shapley per unit cost for problems, their differences and the revenue collected from the loads. It is important to observe that the overall revenue collected (83.1) is approximately equal to the amount paid to the generators (80.62). An error is less than 3%. V. CONCLUSION Although the development of a full-blown market for ancillary services is globally regarded as the long-run objective, it has to be stated that present application of this market is far from the objective, and many issues are to be faced and resolved. Among these are lack of standards, volatile market prices, payment methods and cost allocation issues. In some cases pure market means can be used to provide an ancillary service. However, pure market means have the drawback that the costs of providing the service are sometimes not properly recovered. Although economic theory suggests that they would eventually be recovered, it is not always advisable to set prices only by market means because of the large impact of ancillary services on the security of supply. Thus, for those markets that must incorporate cost recovery as a part of the criteria for provision of ancillary services, some minimally intrusive method for the allocation of costs is required. The advantage of the Aumann-Shapley cost allocation scheme, which was proposed in this paper, is that it is based on marginal costs and thus provides proper signals for economic efficiency. Also, contrary to the direct application pf the marginal costs, revenues collected from the transmission agents are equal to the cost incurred by transmission system in acquiring the corresponding service. REFERENCES [1]

[2]

[3]

[4]

Jin Zhong, “On Some Aspects of Design of Electric Power Ancillary Service Markets”, Thesis for the degree of doctor of philosophy, Department of Electric Power Engineering, CHALMERS UNIVERSITY OF TECHNOLOGY, Göteborg, Sweden 2003 B.G. Gorenstin, S. Granville, J.C.O. Mello, J.A. Medeiros, L.R.M. Regino, A.C.G. Melo, L.G. Marzano, J.S. Ojeda, A.L.M. Marcato, “Ancillary Service in Deregulated Electric Power Industry”, 39-203 Session 2000, Cigre A. Cali, S. Conti, G. Tina, “Ancillary services in deregulated electricity power industry: a structured comparison”, Proceedings of the IASTED International Conference, Power and Energy Systems, November 19-22, 2001, Tampa, Florida, USA “Methods and tools for costing ancillary services”, Task Force 38.05.07

R. Hirvonen, R. Beune, L. Mogridge, R. Martinez, K. Rouden, O. Vatshelle, “Is there market for reactive power services - possibilities and problems”, in Proc. CIGRÉ, 2000, paper 39-213, CIGRÉ JWG. 39/11 2000 [6] E. Nobile, A. Bose, K. Tomsovic, “Bilateral market for load following ancillary services”, Power Engineering Society Summer Meeting, 2000. IEEE Volume 2, 16-20 July 2000 Page(s):704 - 706 vol. 2 [7] “An introduction to black start”, National Grid Company plc, a document from www.nationalgrid.com [8] B. Kirby, E. Hirst, “Maintaining system blackstart in competitive bulkpower markets”, Consulting in Electric-Industry Restructuring Oak Ridge, Tennessee [9] MA Xingwang, D.I. Sun, K.W. Cheung, “Evolution toward standardized market design”, Power Systems, IEEE Transactions on Volume 18, Issue 2, May 2003 Page(s):460 – 469 [10] I. Arnott, N. Singh, T. Rusin, A. Bose, N. Cukalevski, J. La Grange, “Frequency control in a market environment”, 39-205 Session 2002, Cigre [11] S. Stoft, “The demand for operating reserves: key to price spikes and investment”, Power Systems, IEEE Transactions on Volume 18, Issue 2, May 2003 Page(s):470 – 477

BIOGRAPHIES Igor Kuzle (S’94-M'97-SM'04) was born in Tuzla, Bosnia and Herzegovina, in 1967. He went to primary and secondary school in Pozega, Croatia. He received his B.Sc.EE, M.Sc.EE and PhD degree from the Faculty of Electrical Engineering in Zagreb, in 1991, 1997 and 2002 respectively. He was awarded with faculty annual award "Josip Loncar". Since graduation, he has been working at the Faculty of Electrical Engineering, Department of Power Systems. He is presently an Assistant Professor. He published more than 150 scientific papers and practical project studies. He has been a licensed engineer of electrical engineering since 1999. His scientific interests are problems of dynamics, control and maintenance in electric power systems and open electricity market. Darjan Bosnjak (S’06) was born in New York, USA on 1983. He is currently finishing Master thesis at the University of Zagreb, Faculty of Electrical Engineering and Computing, Department of Power Systems. His area of interest is power system ancillary services as well as deregulation of power systems. He is a student member of IEEE. Sejid Tesnjak (M'99-SM'04) was born in Prnjavor, Bosnia and Herzegovina in 1949. He graduated at the Faculty of Electrical Engineering in Zagreb 1972, branch Power Systems. He finished his MSEE studies 1977. School year 1981/82 he spent in Germany at the Ruhr Universitaet Bochum, at the Motor Engineering Faculty, Department for Measuring and Regulation. He finished his Ph. D. studies at 1984. At present he is an associate professor of electric power dynamics. His scientific interests are problems in electric power systems control, mathematical modelling and simulation of dynamics phenomena in electric power systems.