The South African Grid Code Transmission Tariff Code Version 9.0
This document is approved by the National Energy Regulator of South Africa (NERSA) Issued by: RSA Grid Code Secretariat Contact: Mr. Bernard Magoro Eskom Transmission Division, System Operator P.O Box 103, Germiston 1400 Tell: +27 (0)11 871 2774 Fax: +27 (0)86 663 8418 Email: magorotb@eskom.co.za 2
Table of Contents Paragraph No./Title Page Number 1. Introduction... 4 2. Objectives of the transmission tariff framework... 4 3. Principles for regulation of income... 4 4. Determination of tariff structures and levels... 4 5. Five-year pricing plan... 4 APPENDIX 1: Details of the NTC tariff structure... 5 3
1. Introduction (1) This code sets out the objectives of transmission service pricing and the procedure to be followed in applications to change revenue requirements or the tariff structure. (2) The NERSA will regulate the setting of prices and the structure of tariffs in the industry. Service providers shall therefore be regulated with regard to the prices and pricing structures they may charge customers. (3) Customers shall contract with their service provider for the payment of charges related to transmission services. These charges shall reflect the different services provided. 2. Objectives of the transmission tariff framework (1) NTC transmission tariffs shall be designed in pursuit of the following objectives: Open access to the transmission services at equitable, non-discriminatory prices to all customers Pricing levels that recover the approved revenue requirements of service providers Predictable prices over time to customers Pricing signals that reflect the cost structure of the services provided Optimal asset utilisation Unbundling of service offerings and cost-reflective pricing of each service component 3. Principles for regulation of income (1) The NERSA will develop a regulatory framework that shall determine the form of regulation and the methodology by which the revenue requirements shall be calculated. 4. Determination of tariff structures and levels (1) Service providers shall apply tariff structures and charge in accordance with the transmission licence conditions. (2) Service providers shall comply with the time frame and procedure for changes to tariff levels and structures as set out in the transmission licence. (3) Service providers shall inform customers of the proposed price changes, and the planned implementation time frame, at the time that the proposals are submitted to the NERSA for approval. Service providers shall notify customers of approved changes to tariff structures and/or levels before implementation. (4) Service providers shall make their approved tariffs structures and calculation methodologies and procedures publicly available in a form approved by the NERSA. (The approved National Transmission Company (NTC) tariff structure is described in Appendix 1.) 5. Five-year pricing plan (1) The NTC shall annually publish a five-year rolling forward pricing curve for transmission tariffs based on the TS development plan as described in the Network Code, section 7.7. 4
APPENDIX 1: Details of the NTC tariff structure 1 A1.1 Introduction Non-discriminatory transmission pricing is central to the provision of non-discriminatory access. The NTC tariff structure described below shall be applied to all NTC customers. The NTC recovers the NERSA approved costs associated with owning, maintaining and operating a transmission system (TS) on an annual basis through transmission tariffs charged to the users of the TS. Several categories of costs exist. Firstly, there is the cost associated with building, maintaining and operating a TS, the core transmission business. These costs will now be split between transmission transformation and distribution system costs. The transmission transformation distribution system cost will again be divided, to cover shared costs and customer specific cost. Secondly there are costs incurred to finance transmission assets used to connect specific customers. The third cost category relates to the energy consumed as real power losses on the TS, and finally there are costs related to the purchase of ancillary services to ensure the reliable operation of the TS. A1.2 Components of the transmission tariff From the above it follows that the transmission tariff shall be divided into a number of components to cover the cost categories. Four components are used to recover the various costs incurred by the NTC: Network charge Connection charge Losses charge Reliability services charge The network charge and the losses charge are based on a technical analysis of power flows in the TS, with annual maximum demand (KVA) or installed capacity (load customers or generators) used for the network charge and energy used or produced for the losses charge. The connection charge is based on the cost of assets used for the benefit of a single customer, and the reliability services charge is determined by energy usage and the cost to the NTC of procuring ancillary services. Except for the connection charge, which is customer specific, the NTC charges are designed to recover 50% of the NTC income per component from generators and the balance from load customers. A1.3 Determination of revenue requirements For the calculation of the network charge it is necessary to know the NTC s revenue requirements. The NTC substantiates its annual cost through a formal budgeting and financial planning process. The regulatory process includes the scrutiny of all suggested cost items at a predetermined level of detail before the annual price increase is approved. The high-level cost categories included in the revenue requirements are as follows: Operational expenses Depreciation Corporate overheads The revenue requirements also allow for an appropriate return on assets, which enables payment of finance charges, taxes and dividends. The cost of losses is equal to the volume of energy consumed as losses on the TS, multiplied by the energy tariff. The recovery of the cost of losses from customers is calculated from the 1 The tariff methodology needs to be approved by the NERSA and will apply for a specified period 5
purchase costs. The volume of energy expected to be consumed as losses is estimated by doing load flow simulations, by comparing these results with the figures obtained during preceding years and by taking into account known factors that affect the volume of losses experienced on the TS. A regular reconciliation of actual losses against estimated volumes is considered prudent and loss factors will be adjusted quarterly to ensure that the calculated losses approximate the actual losses as closely as possible. The revenue required to purchase all necessary ancillary services is estimated during the budgeting cycle with reference to previous years. A1.4 Transmission assets used in calculations To be able to calculate tariffs in line with the cost structure of the NTC, an analysis of the use of the approved transmission assets is necessary. For the network charge and losses calculations, the analysis includes all equipment used at voltages above 132 kv. All transmission lines, transmission voltage transformers and substation equipment operated above 132 kv are included. All transformer bays and associated transformers where the secondary voltage is at 132 kv or lower are excluded. All other NTC assets not included above are intended to be charged separately in future. Currently all these assets are included in the asset base for the network and losses charges. A1.5 Calculation procedure for tariff components The calculation procedure for the four components is as follows: A1.5.1 Network charges To calculate the nodal network charges for generators, load flow simulations are done on the TS as it is planned to be in operation during the next year, with projects due for completion during that year included in the system. Pro rata use of the asset capacities is linked to the respective customers and charged out to them. The sections below give more detail on the procedure. It is important to note up front that the total income from all network charges is scaled to exactly recover the allowed network revenue. (a) System data The base year for the determination of replacement costs of transmission assets is 2003 and shall be updated every five years. (b) Unit capacities All generators make the installed capacities of all units available to the NTC by the end of July each year for the following year. Units in long-term storage may be excluded from the values given if such units will be in extended cold storage for all 12 months of the year in question. (c) Load values Similarly, for load customers, all customers submit the reserved capacities in kw or MW at each point of supply to the NTC by the end of July each year for the following year. Reserved capacities are defined as the expected maximum demand that will be taken as a load from the TS at a specific point of supply. The intention is to specify the reserved capacity in kva or MVA in future, as soon as systems are ready to accommodate the change. Values given are compared with actual maximum demands experienced on the TS during the preceding 12 months, and explanations are expected to be given to the NTC for variations in the reserved capacity, year on year, that are not in line with the provided load forecasts. Any exceptional maximum demands at any point of supply caused by maintenance or other actions by the NTC or by customers load shifting between multiple points of delivery shall be investigated and disregarded where justified. 6
(Note: To ensure realistic reserved capacities that will enable Transmission to properly price and plan the transmission system, required payments will be increased to reflect actual maximum demand for the year in question if this is more than the previously declared reserved capacity. A customer >with multiple points of supply from the TS is advised to declare the various reserved capacities as the maxima during normal operation conditions on their system. If these reserved capacities are exceeded due to operating conditions different from normal, the customer can purchase short-term capacity at the applicable point of supply to cover the shortfall. At present the short-term capacity price is zero rated.) (d) System simulations Using the above information, load flow simulations using a DC approximation of an AC system are done, starting with the base case where all load customers and units are on the TS. Available units are dispatched in proportion to its installed capacity to match generation and load. The base case determines the direction of power flow on every branch in the simulation model. The next step is to do a load flow simulation for every unit on its own. The loads of all load customers are scaled down pro rata to their reserved capacities to match that unit s capacity. (The sum of the scaled reserved capacities will equal that unit s capacity.) (e) Allocating transmission assets to customers From the above simulations outputs it is possible to determine the proportion of each transmission asset that is used for the benefit of each unit. The total value of transmission assets used for each unit is calculated, resulting in locational cost differentiation being generated at this stage. (If more assets are in the supply path, a higher value of assets will be allocated to the unit.) The TS portion intended for security of supply and for redundancy is now established by comparing all allocated assets with the total value of all assets. This calculation gives the percentage of the network directly utilised, with the balance of the network as the TS portion intended for security of supply and for redundancy. (f) Determination of network charge rate for generation customers With the amount of revenue to be recovered as a known value, and the total amount of connected capacities of all units for 50% of income also known, a separate charge ratio is calculated for loads, to ensure the correct revenue is generated. An average rate for generation customers is now calculated, as well as a specific charge (rate and total payment) for each individual generator. (g) Determination of network charges for load customers Network charges to load customers will be in line with the present retail tariff arrangement, using four concentric pricing areas with the Jeppe Street Post Office in Johannesburg as the centre point and 300 km, 600 km and 900 km circles as the borders between the areas. Customers within the 300 km circle attract the base price applied to their respective reserved capacities, and this price is increased by 1%, 2% and 3% for customers in more distant areas. The calculation process used results in an average price that recovers 50% of income for the NTC from the load customers. Four rates are calculated, namely the base rate for the inner circle area, and a 1%, 2% and 3% higher rate for the outer rings. A total payment at each point of supply is also calculated using the four rates and the reserved capacity of each point of supply. 7
A1.5.2 Connection charge (a) Introduction Connection charges cover the cost of network assets that are specifically installed to connect a user or (a group of users) to the TS. Connection charges shall be payable by both load and generation customers. (b) Types of Connections Connections shall be differentiated according to different levels of reliability requested: Standard connections are connections that attract the minimum network investment that will meet the requirements as prescribed in the Grid Code. Premium connections are connections where additional investments have to be made, over and above that of standard connections, at the request of the customer in order to meet specific quality or reliability criteria of the customer and where such investment cannot be justified in terms of the Grid Code. (c) Connection charging principles The following key principles are applicable to the determination and recovery of connection charges for the different types of connections and customers. The connection charging methodology shall ensure that: the TNSP recovers the costs involved in providing the assets which afford the customer a connection to the TS; the connection charges encourage users to share connection sites, as this promotes efficiencies in the provision of assets and other costs which can be realised and shared between users; charges and allocation methods are based on clear and transparent rules that avoid arbitrariness and limit administrative overheads; and the TNSP does not discriminate between any users connecting onto the TS (d) Standard and premium connection charges Connection charges shall be based on the least life-cycle cost criteria as described in the Network Code. For standard connections, the costs of strengthening and expansion of the existing grid to make available a standard connection shall not form part of the connection charges. These costs shall be recovered through transmission use of system (TUoS) charges. The customer therefore only pays for the dedicated assets. For premium connections, the costs of strengthening and expansion of the existing grid shall be recovered as premium connection charges only to the extent that these costs exceed the costs that would have been incurred for a standard connection. Loads and generators shall always be liable for the cost of standard connection assets recovered through a standard connection charge and shall also be liable for the cost of dedicated premium connection assets recovered through a premium connection charge. (e) Distributor connections Standard connection investments for the benefit of the distributor in general and not for a specific customer or group of customers embedded within the distributor shall form part of the rate base with the exception of feeder/line bays. Premium connection investments for the benefit of the distributor shall attract connection charges for all assets above the standard connection investment. Standard and premium connection investments for the benefit of a single customer or group of customers embedded within the Distributor shall be regarded as dedicated investments and shall attract a connection charge. 8
(f) Cross border connections The primary beneficiary of the investment will determine the liability for connection charges. Cross-border generators or utilities connected primarily for the import of electricity to South Africa (SA) will be treated on the same basis as local generators. The local customer base, through TUoS charges, shall cover the standard cost of strengthening and expansion of the grid to import power into SA. Cross-border loads or utilities, connected primarily for the export of electricity from SA, do not benefit local customers in any significant way. The local customer base will not be required to contribute through TUoS charges for the strengthening and expansion of the system to connect such loads or utilities. These will be viewed as premium connections in their entirety. In the event of cross-border connections being of dual purpose (i.e. import and export) the cost of strengthening and/or the expanding the grid will be pro-rated and the portion of the cost attributable to imports into SA will be borne by the local customer base through TUoS charges. Cross-border connectors used for the wheeling of electricity from one country to another will be treated as premium connections, with the relevant utilities bearing the full cost of strengthening and expansion. (g) Funding of connection costs The connection charge shall be payable in full in advance of energising the connection assets. Where a connection is to be commissioned or constructed in phases, payments will be reflective of those phases or key milestones, with full payment details to be set out in the connection quotations and agreements. (h) Operation and Maintenance Charges All costs associated with maintenance and operation of the grid for both the standard and premium connection assets shall be covered in the rate base through TUoS charges. (i) Refurbishment costs Costs for the refurbishment of connection assets shall be evaluated using the least life cycle cost criteria as described in the South African Grid Code. The refurbishment of connection assets shall occur when the equipment is no longer reliable or safe for operation. The NTC shall justify the need for refurbishment. The cost of refurbishment of standard connection assets, excluding premium assets, will be covered in the rate base through TUOS charges. The cost of refurbishment of premium assets will be covered through a new set of connection charges, to be raised at the time, unless these assets have become integrated into the system to the extent that they can no longer be viewed as premium. The customer shall have the right to withdraw the requirement for a premium supply, in which case the NTC shall have the right to dispose of the assets at its discretion. Where the premium supply came about without any identifiable assets, the cost of refurbishment shall be pro-rated between the TNSP and the customer in the same ratio that the original investment was incurred. As an example: In the event of the customer specifying a non-standard conductor type, at premium cost to the standard, one cannot argue that the entire conductor is a premium asset; only the additional cost over and above what the TNSP would have provided. Upon refurbishment, the entire conductor needs refurbishment and therefore the costs have to be pro-rated. (j) Early termination guarantees Upstream reinforcements costs shall not be raised from customers but an early termination guarantee for shared assets, i.e. upstream reinforcements, shall be raised. 9
The early termination guarantee shall be not higher than 50% of the fair share of the upstream reinforcement costs and shall decrease by 1/10th (one tenth) per year, starting four (4) years after the date of connection. (k) Cost allocation rules for shared assets Assets created and paid for through connection charges should generally be for the unique benefit of a specific customer not shared by other customers. However, a situation may arise where sharing takes place from a future date. The connection charging option/solution that is to be adopted for shared assets should achieve the following: Ensure equitable treatment between all connecting customers, Preserve locational signals, Ensure that no customers receive windfall profits, Ensure that there are no free-riders, Facilitate competition in the electricity supply industry, Should as far as possible avoid creating barriers to entry. Where a number of customers jointly make use of connection assets each user will be charged a proportion of the estimated cost of the shared connection assets, calculated on a per MW share of the utilisation of the shared connection assets rather than the first mover paying the initial high costs for the shared connection asset. This rule involves two scenarios: (1) Where the funding of the connection project has been approved in terms of the TNSP s capital investment process and by NERSA, connection charges will be based on the following principles: Standard connection charges for connection assets that could be shared in the future will be based on the ratio of the customer s maximum export capacity to the installed capacity of the connection equipment (referred to as per MW share). For example, if the connection capacity is 100MW and the connection generator s Maximum Export Capacity is 25MW, then the generator would pay 25/100ths of the cost of the connection assets. The remainder is recovered through the rate base. For new customers sharing the above assets, the connection charges will be paid to the TNSP based on the principles described above. Standard connection charges for connection assets that will not be shared will be recovered fully from the connection customer. (2) Where the funding of the connection project has not been approved in terms of the TNSP s capital investment process and by NERSA, or the funding of the connection assets has been approved for later years and the customer wants to bring forward the connection date, connection charges will be based on the following principles: Connection charges for all standard connection assets will be funded fully by the customer. A shared network charge refund shall apply in cases where a new customer makes use of the connection assets funded by the first customer. This refund shall however not be paid to the initial customer but shall be paid to the TNSP and shall go into TNSP s regulatory clearing account. A new customer pays for the existing shared assets as if they were new, because these assets are provided for the lifetime of the connection agreement i.e. the benefits that the new customer gets are no different whether or not the assets are new. Depreciation is not accounted for because the new customer does not face additional charges during the lifetime of the connection agreement for retrofitting/upgrading of older assets, this cost is borne by the electricity end-user. In the case of generators and embedded generators receiving a regulated tariff approved by NERSA and/or selling electricity to an entity regulated by NERSA the customer specific connection assets paid for by the generator or embedded generator through a connection agreement will, at the time of commissioning be considered shared network assets from the point of connection to the point of common coupling and will, therefore, not incur rebate payments if utilised by other customers at any time in the future. 10
(l) Connection Cost Allocation Examples This section provides examples of connection assets required to accommodate most typical installations. It would be unrealistic to expect any allocation rule to accommodate all possible configurations. Some anomalous situations may occur and in those cases connection charges will be derived consistent with the rules described in sections above. Example 1: Looped station (single connecting party) A load or generator is connected to the transmission system via two lines. The connection costs which are highlighted by the dotted lines consist of: Connection Costs: The transformer bay connecting the user to the station and associated metering and protection equipment. Transmission use of system costs The station common costs, typically busbars. The two new line sections ( loop-in sections) and line bays connecting the station to the circuit. Costs associated with decommissioning of the section of the line to be retired. Any upgrading of line protection and communication equipment required as a direct result of the connection. For example if upgrading is required at the existing transmission stations A and/or B the connecting user will be eligible to pay for this cost. Example 2: Deviation from least cost (LC) connection Description A new user connecting to the transmission system can be connected by either a looped connection or a tail-fed station. The tail-fed station is the least cost option but for system reasons a looped connection is selected. 11
Connection Costs The connecting user will only be eligible to pay for the least cost option, which in this case is the cost of the tail-fed line, station common costs and tail fed station. 12
Example 3A: Project approved in the MYPD by NERSA Where a number of users connect simultaneously and jointly make use of connection assets each user will be charged a proportion of the estimated cost of the shared connection assets, calculated on a per MW share of the utilisation of the shared connection assets. The remainder is recovered through the rate base. The same principle will apply if the second user connects a few years after the first user. Capacity of the initial connection (MVA) 250 Cost of the initial assets (Rm) 100 Year 2014 Capacity connected (MVA) 220 Capacity available (MVA) 30 Charge to Developer 1 56 Charge to Developer 2 32 13
Example 3B: Developer funds the project In the case where the developer funds the project, he pays 100% of the connection costs. When subsequent developers use the assets funded by this developer, they pay a proportion of the shared asset costs, calculated on a per MW share of the utilisation of the shared connection assets. These connection costs goes to the NTC and ultimately ends up in the RCA. Capacity of the initial connection (MVA) Cost of the initial assets (Rm) Year Capacity connected (MVA) Cumulative capacity connected (MVA) Capacity available (MVA) Charge to Developer 1 Charge to Developer 2 Charge to Developer 3 Refund to the NTC (Rm) 250 100 2014 2015 2016 2017 2018 100 80 60 100 100 180 180 240 150 150 70 70 10 100 0 0 0 0 32 0 0.0 24 0 0 32 0 24.0 14
Example 4: Developer connects to an existing station Description: A generator/s connects to an existing transmission station. There isn t enough capacity left for the new generators to connect; therefore another transformer needs to be connected. Transformer 1 and Transformer 2 do not provide any standby facility to each other. Connection Costs: Extension of the LV busbar by one transformer bay. The transformer bay connecting the user to the station and associated metering and protection equipment. Transmission use of system costs Extension of the HV busbar by one transformer bay. Capacity of the new connection (MVA) 500 Cost of the new assets (Rm) 100 Year 2014 Capacity connected (MVA) 280 Capacity available (MVA) 220 Charge to Developer 1 (Rm) 28 Charge to Developer 2 (Rm) 28 In the case of generators and embedded generators receiving a regulated tariff approved by NERSA and/or selling electricity to an entity regulated by NERSA the customer specific connection assets paid for by the generator or embedded generator through a connection agreement will, at the time of commissioning be considered shared network assets from the point of connection to the point of common coupling and will, therefore, not incur rebate payments if utilised by other customers at any time in the future. 15
A1.5.3 Losses charge Losses are administered and managed by the NTC. The energy consumed by the TS is purchased from the generators at the contracted or market energy rate. To be able to pay for this energy, the NTC charges both generators and load customers a losses charge, reflecting the relative amount of losses associated with a specific position on the network for a unit or for a load. The loss factors for generators are calculated using a marginal change methodology, and locational differences in losses are accounted for in this process on a nodal basis, giving higher cost of losses to distant generators. Loss factors for loads are calculated according to the present retail tariff arrangement, using four concentric pricing areas with the Jeppe Street Post Office in Johannesburg as the centre point and 300 km, 600 km and 900 km circles as the borders between the areas. A base loss factor for the inner circle is calculated, and one percentage point is added for the subsequent three areas. The charge is calculated so that 50% of the income is received from generators and the other 50% from load customers, as is the case with the network charge. The loss factors are calculated to result in total income from losses to be exactly the budgeted amount, to prevent under or over recovery compared to the cost of losses energy. Quarterly reconciliation and adjustment of loss factors to correct for anomalies will be done, if necessary, to reduce the risk of significant deviations between cost and income over a full year. The first step in the process of calculating the losses is an analysis of actual measured losses during previous years. Corrections are made for the known factors that have major influences on losses. All future plans regarding these known factors are taken into account for the following year, and the expected percentage of losses can be estimated in this way. At this stage the installed capacities of units and the reserved capacities for load customers should be known to the NTC. These values are used in a simulation of the TS where the TS load is scaled to the average demand of the TS, which is total budgeted energy divided by 8 760 hours in the year. Losses are noted for this case. The calculation of the loss factors for generators is made using the standard technique to calculate marginal loss factors. For example, to calculate the marginal loss factor for a specific generator, all other generators will be kept constant while the generator in question is increased by a known amount, e.g. 100 MW. All loads will be scaled up by the same percentage to cover the change in generation as well as the change in losses. Since the differences in TS load as well as in transmission losses are now known, the marginal loss percentage can be defined as the difference in losses divided by the difference in load on the TS. For load customers an iterative process is used to determine the base loss factor. The process is finished as soon as the resultant computation of all losses related to load customers in all four of the areas result in a value that is equal to the budgeted value. By multiplying the loss percentage for a specific customer by the energy rate for losses, a new losses energy rate is derived for every customer. This losses energy rate is applied to the metered energy value of the unit or the load to determine the amount payable as the losses charge, on a monthly settlement basis. The actual consumption in each time period (peak, standard and off-peak) will be multiplied by the relevant loss factor and the cost of losses recovered at the normal energy rates applicable to losses energy. In other words: losses = delivered energy (kwh) x (loss-factor 1) cost of losses = cost of losses t = losses t (kwh) x P t (c/kwh) cost of losses = {delivered energy t x (loss factor 1)} x P t Where t = the appropriate losses time period; and P t = energy price for losses time periods. 16
(Note: The losses energy time periods may or may not be same as normal energy time periods, depending on the supply arrangement between Transmission and the supplier of the losses energy.) The NTC may contract with one or more generators for the supply of the energy to be consumed by the TS as losses. The NTC is able to balance the cost of purchase and revenue from sales of losses if both sides of the transaction are done with known and fixed rates. If no hedging contract can be negotiated, the NTC will have the right to adjust the loss factors proportionally and in a non-discriminatory fashion to reflect the actual cost of losses in such a way that it matches the approved revenue on a quarterly basis. A1.5.4 Reliability services charge The purpose of the reliability services charge is to earn revenue to pay for the purchase of ancillary services from mainly the generators, but also from end-use customers in certain cases. The total budgeted cost of ancillary services is determined by the NTC, and an energy rate is calculated for the reliability services charge that would allow the specific amount of budgeted revenue to be collected based on the budgeted amount of energy to be generated and delivered via the NTC. The NTC may enter into contracts in order to hedge the risk of purchasing ancillary services. The NTC shall comply with the NERSA s requirements for balancing ancillary services costs and reliability services income. A1.6 Timing and promulgation In order to enable the timely calculation of tariff levels for promulgation and implementation by 1 January every year, generators and loads will submit their installed capacities (generators) and reserved capacities (loads) for the following year, as well as indicative five-year values for the same, by 31 July. Since the schedule from this date to successful promulgation is tight, it is important that generators and loads adhere to this requirement to prevent delays in the implementation of annual price increases. 17