Reactive Power Management in Deregulated Electricity Markets- A Review

Transcription

1 Reactive Power Management in Deregulated Electricity Markets- A Review Jin Zhong, Student Member IEEE and Kankar Bhattacharya, Member IEEE Abstract- With the restructuring of the electric power industry during the past decade, operation and control strategies have undergone a shift in paradigm. Certain activities that were earlier considered as part of the integrated electricity supply (such as voltage and frequency control) are now treated as separate services and often independently managed and accounted for. This paper examines the management of reactive power services in deregulated electricity markets around the world. From the review several diverse methods for handling reactive power within the deregulated market framework emerges. While in many of the markets, proper financial compensation mechanisms exist to compensate the providers for their service, some others continue to handle reactive power through regulatory frameworks and technical operation guidelines. Index Terms- Deregulation, ancillary services, reactive power management, reactive power tariffs I. INTRODUCTION HE power transmission capability available from a Ttransmission line design is limited by technological and economical constraints. Therefore, in order to maximize the amount of real power that can be transferred over a network, reactive-power flows must be minimized. Consequently, sufficient reactive power should be provided locally in the system to keep the bus voltages within nominal ranges in order to satisfy customers equipment voltage ratings. In deregulated electricity markets, provision for reactive power support needs to be made by the Independent System Operator (ISO) in order to meet the contracted transactions in a secure manner. This procurement of reactive power services should be done taking into account the perceived demand conditions, mix of the load and availability of reactive power resources. Most often, the independent generators or customers own the resources for reactive support such as synchronous generators, synchronous condensers, capacitor banks, reactors, static var compensators and FACTS devices, and the ISO needs to enter into contracts with them for such provision. In vertically integrated electricity systems, reactive power support was part of the system operator s activities and the expenses incurred in providing for such services were included within the electricity tariff charged to customers. In This work is being supported by Sydkraft Research Foundation, Sydkraft AB, Sweden, for the research project on ancillary services pricing. The authors are with Department of Electric Power Engineering, Chalmers University of Technology, S-4296 Gothenburg, Sweden. deregulated systems on the other hand, reactive power management is handled and charged for, as like several other ancillary services, separately. The reactive power management and payment mechanisms however, vary for each deregulated electricity market in the way the contracts are framed and the markets are operated. Usually the ISO enters into contracts with reactive power providers for their service provisions. In the US context, as per the NERC s Operating Policy-0 [], only that reactive power provided by synchronous generators are considered as ancillary services and can receive financial compensation for their services. This is also true for the UK and Australian markets. The Australian market additionally considers reactive power from synchronous condensers also as ancillary service. On the other hand, deregulated markets in the Nordic countries do not have any provision for payments towards reactive power services. For example, in Sweden the responsibility for managing reactive power lies with network companies, with certain rules from the ISO, stipulating that there should be no exchange of reactive power over different network voltage levels and transformers. To meet these requirements, individual entities, such as local and regional networks, have to make provision for their own reactive power. In a similar manner in the Netherlands, the network companies have to take care of their reactive power requirement individually. These companies however purchase reactive power locally through bilateral contracts with generators or through exchange with other network companies. Those generators that have been contracted for the reactive power service are paid for their reactive power capacity only. No payment is made for reactive energy. In this paper, we attempt to examine this particular aspect of deregulated electricity markets across different countries- how reactive power is managed and financially compensated for. In earlier related papers by the authors, [2], [3], various issues relating to development of market based mechanisms for reactive power and optimal procurement schemes for reactive power by the ISO have been brought out. The present work seeks to bring out the diversity amongst the various systems in handling this important technical issue of reactive power management while also touching upon on how these markets work. However, the coverage of this paper has been limited by availability of information in many cases, and the restrictions on space. We attempt to cover some of the important developments and market models while also trying to broaden /02/$ IEEE 287

2 our coverage of deregulated markets worldwide. II. THE USA The North American Electric Reliability Council (NERC), in its White Paper on the Proposed Standards for Interconnected Operations Services (IOS) [4], notified that only generation sources shall be entitled to provide reactive power as an IOS / ancillary service. The other entities providing reactive support shall not be considered as IOS nor be eligible for any financial compensation. However, the operating authority coordinates the use of static reactive supply devices throughout the system. Also all synchronous generators are required to be operating with their excitation system in automatic voltage control mode so that the generators reactive power output during emergency conditions do not fall short of the reactive capability. This is particularly true when the generators are operating at points higher than rated real power so that the armature current heating limits restrict the reactive power output. In such a situation, if the generator terminal voltage falls (due to certain contingencies), the reactive output from the generator would be much reduced and endanger system stability. A. New York ISO The New York ISO (NYISO) is responsible for providing reactive power support services, and this is provided at embedded cost-based prices. Generating resources, which operate within their capability limits, are directed by NYISO to produce / absorb reactive power to maintain voltages within their limits [5]. The NYISO computes the cost of reactive power support by summing all its payments to suppliers that provide the support. It includes the total annual embedded cost, any applicable lost opportunity cost and any balance account adjustments from previous year. The annual embedded cost component is obtained from the annual fixed charge rate associated with resource capital investment, current capital investment of the resource (generator or condenser) allocated for supplying reactive power support and other operating and maintenance expenses. ) Lost Opportunity Cost A generator receives a component of payment accounting for the Lost Opportunity Cost (LOC) when directed by NYISO to reduce its real power output level. The LOC calculation is based on the following factors: Real time long-term based marginal price (LBMP) Original real power dispatch and the new dispatch point Bid curve of generator supplying reactive power service Fig. describes the calculation of the LOC for a generator, which decreases its real power output to provide more reactive power service. In Fig., P RT is the real-time long-term based marginal price (LBMP), f(p) is the bid curve of the generator supplying reactive support. D and D 2 are the original and new dispatch points respectively while B and B 2 are the corresponding bid prices at D and D 2. P RT B B 2 $ LOC D 2 P, MW Fig.. Method for calculating Lost Opportunity Cost by NYISO [5] D Real Time LBMP (P RT ) Bid cost curve = f(p) As the real power output is decreased, the generator receives lesser revenue from the sell of energy although by way of this reduced generation, it saves some generating cost. The reduced income ( R) for the generator can be described by equation (). D R P RT D D 2 f P dp () D2 The first term in () denotes the revenue lost by the generator while backing down its real power output from D to D2, and the second term denotes the corresponding reduction in generation cost. Note that R also equals the savings to the ISO. The saving of the generator ( S) from reduced real power output can be given as, D S B (D D 2 ) f(p) dp (2) D2 The LOC of the generator equals to the difference between equation () and equation (2), i.e., LOC (PRT B) (D D2) (3) B. California ISO In the California system, the ISO procures reactive power support services on long-term contracts from reliable must-run generating units [6]. The actual short-term requirement is determined on a day-ahead basis, after the real power market is settled and the energy demand and schedules are known. Thereafter the ISO determines the location-wise amount of reactive power required based on system power flow analysis. Daily voltage schedules are issued to contracted generators and the transmission operators within the region. The generators are mandated to provide reactive power within the power factor range of 0.90 lag and 0.95 lead (Fig.2). For reactive power absorption / generation beyond these limits, the generators are financially compensated for, including a payment if they are required to reduce their real power output. 288

3 Q, MVAr 0 Field current limit No Payment in this Region Generator receives financial compensation PMax Under-excitation limit 0.9 pf Lag Armature current limit P, MW 0.95 pf Lead Fig. 2. The mandatory (no payment) reactive power requirement and the ancillary service component that receives financial compensation in the California system C. PJM Interconnection The Pennsylvania - New Jersey - Maryland (PJM) interconnection restructured its operations in 997 and PJM was established as the ISO. As per the report of the Market Monitoring Unit [7] and [8] reactive power was recognized as an ancillary service by PJM and two distinct components were segregated. The first component was the reactive capability at rated capacity of a generator while the second was the reactive capability at reduced generator output levels. It has been mandated that reactive power supply and voltage control services will be provided directly by the individual transmission providers. The transmission providers in turn have defined the tariff rates for their customers, in this case, load serving entities either within the zone or outside. For the first component, i.e., the reactive capability at rated capacity, the customer pays a charge proportional to the total generation owner s monthly revenue requirement and the amount of monthly use of the network. Regarding the second component, generators are paid for their opportunity costs incurred as a result of increasing their reactive power production by reducing real power output. This is paid only to those generators that are directed to operate in such a mode and the opportunity cost is equal to the locational marginal price less the generator s bid for each MW that they back down. III. IN EUROPE A. The United Kingdom ) Reactive Payment Arrangement In the U.K. electricity market, the National Grid Company (NGC) handles the role of the ISO. The Grid Code places a minimum obligation on all generating units, with a power generating capacity more than 50 MW, to provide a basic (mandatory) reactive power service. In order to receive payment for this service, the generators must enter into a Default Payment Mechanism (DPM). Alternately, the generators can offer the mandatory reactive power service through the tender market by structuring their bids to reflect the value that they perceive their service is worth. This way of meeting the mandatory Grid Code with a market mechanism is termed as Obligatory Reactive Power Service (ORPS). The income a generator could receive by providing reactive power varies according to the number of generators who can provide that service within a zone and the relative need [9]. Further, generators with reactive power capability in excess of the Grid Code can offer an Enhanced Reactive Power Service (ERPS). The Default Payment Mechanism was initially (in 997/98 when the scheme was started) based on two components -- a capability payment component and an actual utilisation based payment component with a ratio of 80:20. This ratio underwent a staircase phasing of the capability component and since April 2000, the ratio has been 0:00 and Default Payment Mechanism is based on metered reactive utilisation only. Under the new arrangements, a reactive power market has been formalised by NGC by inviting tenders, which can be for either ORPS or ERPS. Any prospective service provider, irrespective of whether it receives payments under the DPM arrangement or not, can offer a tender. In this way the provider has greater assurance of a given level of income. Unlike the DPM, the bidders are able to offer specific prices for capability and utilisation, thereby allowing greater flexibility to offer payment terms that are more cost reflective of the actual service provided. There are two tender processes a year, which start on April and October, respectively. 2) Structure of Bid Offers in the Tender Market The tender bids submitted by reactive power service providers comprise two components: (a) Capability price component (refer Fig.3). (b) Utilization price component (refer Fig.4). When a reactive service provider bids for capability prices, he can choose to bid prices for both leading and lagging MVAr capability or just one of them. It can also bid for two types of capability price bids () for synchronous capability price and (2) available capability price. Fig.3 gives an example cost function that could be offered for synchronized and available capability. For each type of capability price, generators can offer up to three incremental prices for both leading MVAr capability and lagging MVAr capability. For utilisation bid price, the criteria is similar to above, up to three incremental prices can be offered for leading and lagging Mvar (Fig.4). Lead Mvar Synchronized capability price Avaliable capability price Lag Mvar Fig. 3. Tender bid price structure for synchronized and available reactive power capacity 289

4 Lead Mvar Utilisation price Fig. 4. Tender bid price structure for reactive power utilisation Lag Mvar Some evaluations have been given in [0] and [] to describe the bidding trends in the reactive power tender markets for both ORPS and ERPS covering the periods April to September 999 and October to March 2000 respectively. From the analysis the following observations are made: As of April 2000, there were a total of 95 generating units with a reactive power agreement with NGC within the UK reactive power tender market system. All the tenders were for the provision of ORPS and none were for ERPS. It would be desirable for NGC to receive tenders for ERPS also. It was apparent that at least 50% of the bidders were seeking greater remuneration of their reactive power capability although still broadly following the payment profile of DPM. A few tenders selected a simple structure of available capability payment, reflecting a linear payment rate per MVAr of reactive power available. Some offered a flat available capability payment rate. This type of tenders gave little incentive to NGC to accept these generators to maintain capability. Majority of the tenders selected the payment structure based on steeper incremental capability prices at higher MVAr outputs. These tenders give clear signal of generators preferred operating range. In a number of the marginal cases, the steep incremental capability prices may influence NGC to decide whether to accept or reject a market agreement. Most tender offers included capability prices for hours available, while a significant number of tenders wished to be paid on the basis of the hours synchronised. B. Sweden The Swedish electricity system is characterized by bulk power flows from the north, where a major share of generation is located, to the south, where most of the load centers are, over long distance transmission lines. As reactive power can not be transmitted over such distances, it should be provided by local sources. Svenska Kraftnät owns the national grid (400 kv and 220 kv), and also carries out the responsibilities of the ISO while the regional and local network companies operate the sub-transmission and distribution networks (30 kv and less) [2]. Reactive power services are provided on a mandatory basis in Sweden and as of now, there is no scheme for financial compensation to the providers of this service. The reactive power exchange on the national grid is controlled by instructions from Svenska Kraftnät. It is recommended that reactive power flow between different parts of the grid be kept near zero. The ISO has the right to the supply of reactive power from spinning generators connected directly to the national grid. The regional network companies are responsible for voltage control in their respective areas. Under normal conditions the regional network operators use as much static reactive power production as possible. Large generators are rarely used for secondary voltage control and are reserved for serious situations. Such units operate at a constant reactive power output, with a stable operating point considering vibration and losses. ) Formal Agreements for Reactive Power Transfer Over the Grid For power transactions over the network, Svenska Kraftnät enters into formal agreements for reactive power exchange with independent generators and regional networks. Agreement for feeding power into the national grid is mostly with producers but in certain cases, can also be with regional networks. Following are some of the standard set of agreements: A hydro unit connected directly to the national grid is required (mandatory) to be able to inject as well as absorb reactive power as per the following limits. Reactive Injection 3 PMax Reactive Absorption PMax 6 A thermal unit connected directly to the national grid is required (mandatory) to maintain capability of reactive power injection as per the limits, given below. However, it has no requirement on absorption of reactive power. Reactive Injection PMax 3 A regional network with agreement to inject real power into the national grid is required to maintain a capability to inject reactive power, depending on the instantaneous real power injection, as given below. Reactive Injection Pinstantaneous 3 There is no requirement on absorption of reactive power from the national grid. Also there is no specific requirement from a generator connected to the regional grid. A regional network with agreement for drawing real power from the national grid, there is no requirement for injection or absorption of reactive power to/from the national grid. 290

5 C. Finland The Electricity Market Act and the point of access tariff in 995 opened the Finish electricity market for competition and in June 998 Finland became a price area on the NordPool exchange. The Finnish ISO, Fingrid is responsible for maintenance of system voltages and accordingly, it supplies reactive power as per the general supply principles concerning reactive power. The voltage level of the main grid is controlled using reactors and capacitors. The voltage ratio between different voltage steps is controlled with tap changers of the transformers. ) Reactive Power Reserve Service: Fingrid is also responsible for the maintenance of adequate reactive power reserves in the Finnish power system. This is done through the use of its own resources and also by acquiring reactive reserves from independent parties [3]. This provision for reactive power reserves is a mandatory service as of now. It is likely that a tariff mechanism for financial compensation will be in place for this service by the year 2002: As per the guidelines, generators of more than 0 MVA rating, are required to maintain reactive power reserves during the normal status of the power system: For generators connected to the 400 kv grid, the entire reactive capacity should be available as momentary reserves and mandatory, with the exception of that amount consumed by transformers and the plant itself. For generators connected to 220 kv and 0 kv grid, the mandatory momentary reactive power reserve should not be less than half of the calculated reactive capacity corresponding to a power factor of 0.9. The rest can be used as a commercial service. For generators connected to the grid at voltage levels less than 0 kv, half of the reactive power intake capacity at the generator s voltage level, is also required to be reserved as momentary disturbance reserve and mandatory. IV. AUSTRALIA The Australian electricity market and its ISO, the National Electricity Market Management Company (NEMCO) recognises only that reactive power provided by synchronous generators and synchronous condensors, as ancillary services and financial compensation is made available to them for their service provisions [4]. All reactive power ancillary service providers are eligible for the availability payment component- for their preparedness in providing the service when called for. Further, the synchronous compensators also receive an enabling payment component- when their service is activated by the ISO for use. On the other hand, a synchronous generator receives the compensation payment component- based on its opportunity cost, and paid when it has been constrained from operating according to its market decisions. The total payment for reactive power service is shown in Fig.5. Payment for Reactive Power AVAILABILITY COMPONENT Fig. 5. Payment for Reactive Power ENABLING COMPONENT (for synchronous compensators only) COMPENSATION COMPONENT (Generators only) A. Mandatory and Ancillary Reactive Power Services The provision for reactive power from generators is separated in two categories: The mandatory reactive power support, and Reactive power as an ancillary service As explained in Fig. 6, it is mandatory for the generators to provide reactive power within the operating power factors of 0.9 lagging and 0.93 leading. Beyond this mandatory component, is the ancillary service component, which is left to the generators to offer. However there is a portion beyond the ancillary service component, which is left undefined [5]. Q Undefined Mandatory Undefined Field limit PMax 0.9 pf lag 0.93 pf lead Ancillary service component Fig. 6. Generator Reactive Power Definitions in the Australian Market The basic voltage control scheme adopted in NEMMCO is as follows [6]: Various energy management system functions (such as load flow analysis) are used to determine the reactive power requirement in the system. Reactive power support elements such as capacitor banks, reactors and SVC are switched as required. Next, reactive power support from generators that are currently on-line, is used to the extent that their normal output is not restrained. Here, those generators not contracted for ancillary services are also called in to provide the mandatory amount of reactive power. Those contracted for reactive power can be asked for amount more than the mandatory amount, subject to financial compensation. Next, select synchronous compensators for the specific area from a merit order based on enabling prices are activated. If further reactive power is required, the ISO considers constraining the units real power generation. If the total reactive support available from all sources, as discussed above, is insufficient to ensure system security under certain conditions, market trades can be curtailed. P 29

6 V. CONCLUDING REMARKS In deregulated electricity markets, provision for reactive power support and devising appropriate pricing mechanisms for that, is a complex problem. In this paper we have attempted to examine the procedures and schemes adopted in some of the deregulated electricity markets regarding management of reactive power. In the British reactive power market, the service is bid by providers comprising capability price component and utilisation price component. In New York, in addition to the payment for embedded cost, a payment for lost opportunity cost is also calculated. Australia s reactive power service includes mandatory service and ancillary service components, and the service is paid for in three components: availability, enabling and compensation. In many deregulated power systems however, the independent generators continue to provide reactive power support without getting paid from the ISO. VII. BIOGRAPHIES Jin Zhong obtained her B.Sc. (Eng) from Tsinghua University, China in 995 and M. Sc. (Eng) from Electric Power Research Institute, China in 998, where she continued as a researcher till 999. She joined the Department of Electric Power Engineering, Chalmers University of Technology in 999, and obtained the Licentiate of Technology degree from there in 200. She is currently continuing her research towards a Ph.D from Chalmers. Her areas of interest are electricity sector deregulation and ancillary service pricing. Kankar Bhattacharya obtained his Ph.D. in Electrical Engineering from Indian Institute of Technology, New Delhi, India, in 993. From , he worked at Indira Gandhi Institute of Development Research at Bombay, India. Since 998, he is with Chalmers University of Technology, Gothenburg, Sweden, in the department of Electric Power Engineering and is currently an Associate Professor. His research interests are in power system dynamics, stability and control, economic operations planning, electricity pricing and electric utility deregulation. VI. REFERENCES [] North American Electric Reliability Council, NERC Operating Policy- 0 on Interconnected Operation Services, Draft-3., February [2] K. Bhattacharya and J. Zhong, Reactive power as an ancillary service, IEEE Trans. on Power Systems, May 200, pp [3] J. Zhong, Design of ancillary service markets: Reactive power and frequency regulation, Technical Report 392L, Chalmers University of Technology, Sweden, 200. [4] North American Electric Reliability Council, White Paper- Draft of the Proposed Standards for Interconnected Operations Services, ISO Task Force, NERC, June 999. [5] New York Independent System Operator Ancillary Services Manual, 999. [6] California Independent System Operator Corporation, Ancillary services requirement protocol, FERC Electricity Tariff, First Replacement Volume No.II, October [7] PJM Interconnection LLC, Report to FERC on Ancillary service markets by the Market Monitoring Unit, PJM Interconnection, April [8] PJM Interconnection LLC, PJM open access transmission tariff: Schedule-2, Fourth Revised, Vol., Issued Feb.200. [9] The National Grid Company plc., An introduction to reactive power: Ancillary Services- Reactive Contracts, June 998. [0] The National Grid Company plc., NGC reactive market report: Fourth Tender Round for Obligatory and Enhanced Reactive Power Services, November 999. [] The National Grid Company plc., NGC reactive market report: Fifth Tender Round for Obligatory and Enhanced Reactive Power Services, May [2] Svenska Krafnät, OPF, constraints for reactive exchanges between the SvK kv network and other networks in Sweden, Internal paper. [3] FINGRID OY Main Grid Service Conditions, January 999. [4] National Electricity Market Management Company (Australia), National electricity market ancillary services, November 999. [5] National Electricity Market Management Company (Australia), Generator code reactive obligations, November 988. [6] National Electricity Market Management Company (Australia), Operating procedure: Ancillary Services, Document Number SO_OP