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REGULATORY RULES ON NETWORK CHARGES FOR THIRD-PARTY TRANSPORTATION OF ENERGY

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REGULATORY RULES ON

NETWORK CHARGES FOR THIRD-

PARTY TRANSPORTATION OF

ENERGY

NERSA Consultation Paper

MAY 2011


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TABLE OF CONTENTS

Contents DEFINITIONS ........................................................................................................................ 3

ABBREVIATIONS AND ACRONYMS ........................................................................... 8 CHAPTER 1 – INTRODUCTION TO NETWORK CHARGES ........................................ 10

1.1 Introduction ............................................................................................................ 10

1.2 Background to the Development of Network Tariffs in South Africa ............... 12

1.3 Electricity Network Pools in South Africa ............................................................. 13

1.3.1 Transmission network ..................................................................................... 13 1.3.2 National or regional distribution ..................................................................... 14 1.3.3 Distribution network ....................................................................................... 14 1.3.4 Distribution network charges .......................................................................... 14

1.4 Scope, Objectives and Requirements ..................................................................... 15 1.4.1 Scope of the Consultation Paper ..................................................................... 15

1.4.2 Objectives ....................................................................................................... 15 1.5 Network Tariff Requirements ................................................................................ 16

1.5.1 National vs. regional network tariffs .............................................................. 18

1.5.2 Pooling of networks ............................................................................................. 19

1.5.3 Tariffs structure for bilateral agreements ........................................................ 19

1.6 General Market Rules............................................................................................. 20 1.6.1 Licensing and ring-fencing ............................................................................. 20

1.6.2 Network service vs. retail electricity service .................................................. 21 1.6.3 New generation capacity generators ............................................................... 21 1.6.4 Commercial arrangements .............................................................................. 22

1.6.5 Non-discrimination ......................................................................................... 22 CHAPTER 2 – TRANSMISSION USE-OF-SYSTEM (TUOS) CHARGES ...................... 23

2.1 Network Charge (Transmission Infrastructure Charge) ........................................ 23 2.1.1 Transmission (Tx) infrastructure charge for loads .......................................... 23 2.1.2 Transmission Infrastructure charge for Generators ........................................ 24

2.1.3 Reliability Charges to loads and generators......................................................... 27 2.1.4 Service and administration charges to loads and generators .......................... 27 2.1.5 Losses charges for loads and generators ......................................................... 28

2.2 Transmission Connection Charges ......................................................................... 28

CHAPTER 3 – DISTRIBUTION USE-OF-SYSTEM CHARGES ..................................... 30 3.1 DUOS Charges for Loads ...................................................................................... 30

3.1.1 Structure of DUOS tariffs ............................................................................... 30 3.1.2 Application of DUOS tariffs ........................................................................... 30

3.2 DUOS Network Charges Component for Loads .................................................... 31

3.3 DUOS Losses Charges for Loads .......................................................................... 32

3.4 Reactive Energy Charges ....................................................................................... 33 3.5 Customer Service and Administration Charges ..................................................... 33 3.6 DUOS Charges for International Customers .......................................................... 33 3.7 DUOS Charges for Generators ............................................................................... 33


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3.8 Distribution Connection Charges for Generators ................................................... 36 CHAPTER 4 – POWER WHEELING AND CONTRACTUAL MATTERS ..................... 37

4.1 Charges for distribution connected generators ....................................................... 37 4.2 Connection and Use-of-System Agreement ........................................................... 37

4.3 Wheeling of Energy (Third-Party Access) ............................................................. 38 4.4 Special Supply Conditions ..................................................................................... 41 4.5 Contractual Arrangements..................................................................................... 42 4.6 Rules for the reconciliation of accounts ................................................................. 43 4.7 Subsidies and Levies ................................................................................................ 45

CHAPTER 5 – PUBLIC CONSULTATION PROCESS ..................................................... 47


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DEFINITIONS

Administration charge

The administration charge covers the costs of the administration of the account. It is a contribution towards fixed costs such as meter reading, billing and meter capital. It is a fixed charge payable every month whether electricity is consumed or not.

Annual utilised capacity

Annual utilised capacity is the higher of the customer’s NMD or maximum demand, measured in kVA, registered during a rolling 12-month period. This is inclusive of any contingency capacity required.

Chargeable demand The highest average demand, in kVA, measured over any demand-integrating period of thirty consecutive minutes (30-minute integrating periods) recorded during the chargeable time periods in a billing month.

Connection charge

The connection charge is the charge allocated to the customer for the capital costs of new or additional capacity (irrespective of whether new investment is required or not) that is not covered by the tariff. It is payable in addition to the tariff charges as an up-front payment or as a monthly connection charge where the distributor finances the connection charge.

Consumption The energy used by a customer during a specific period, measured in kWh.

Contestable customers

Customers approved by NERSA to select a retailer other than the local distribution company where the customer is connected. This customer is considered a network service customer of a distributor.

Contingency capacity

The capacity required from the distributor under a credible scenario if own generation or load control mechanisms fail i.e. the additional short term capacity required to satisfy the capacity required during the contingency.

Direct (Transmission) customer

A customer whose supply is taken directly from the transmission network, without utilising the distribution network.


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Distribution charges

The charges applicable for the use of the distribution system (DUOS charges) and the connection to the system (connection charges).

Distribution system The distribution system transports power to users at voltages of <132kV as defined in the SA Grid Code.

Distribution use-of-system charges

DUOS charges are unbundled regulated tariffs charged for making capacity available on the distribution system to contestable and indirect customers. DUOS charges comprise unbundled DUOS network charges, embedded TOUS charges, charges for energy losses – for both distribution and transmission losses, reactive energy charges and levies to recover subsidies.

Distributor A regulated business that constructs operates and maintains the distribution system. The distribution business will also purchase transmission network services and may provide retail services such as purchasing of energy and meter reading, billing, customer service etc.

Diversity

Diversity arises when two or more loads’ maximum demand do not necessarily occur simultaneously. Customers with two or more loads receiving the benefit of diversity are charged on the simultaneous maximum demand and not the sum of the individual load’s non-simultaneous maximum demand, which may be higher.

Diversity factor

Ratio of the sum of the non-coincident maximum demands of two or more loads to their coincident maximum demand for the same period. The further away from the individual supply points, the higher the diversity.

Embedded customer

A customer whose supply is taken from the distribution system.

Embedded distributed generation

An embedded distributed generator is a generator embedded in/connected directly to the distribution system.


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Embedded TUOS charges

The distributor must adjust the TUOS charges to take into account the diversified demand of the embedded distribution customers. If the undiversified demand were used, this would result in the receipt of more revenue by the distributor for transmission costs than the actual cost to the distributor for this service. The adjustment of the TUOS charges as charged by the transmission network company is the embedded TUOS charges.

Entry charges Use-of-system charges payable by generators to allow their electricity to enter the electricity network.

Exit charges Use-of-system charges payable by loads to allow their electricity to exit the electricity network.

International customer

A customer supplied outside the borders of South Africa

Licensed area of supply

Licensed area of supply is a legally designated area where a particular supplier has the right to supply electricity to end customers. The distributor’s regulated tariffs for the wires business are only applicable within the supply area for franchise customers as per the distribution licence issued by NERSA. A retailer may also be provided with a licence to service certain customers.

Maximum demand The highest averaged demand measured in kVA during any integrating period (normally 30 minutes) within a designated billing period (usually one month).

Network access charges (NAC)

The network access charge (NAC) is a tariff component that may be applicable in both the structure of retail tariffs and in DUOS. It is a charge that is fixed on an annual basis and is charged as a R/kVA on the annual utilised (reserved) capacity.

Network charges The network charge is a tariff charge payable per premise every month. The network charge recovers network costs (including capital, operations, maintenance and refurbishment) associated with the provision of the network capacity required and reserved by the customer. The network charge in the retail tariff or in the DUOS charges may or may not be the same as in structure and value.


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Network demand charges (NDC)

The network demand charge is a tariff component that may be applicable to both the structure of retail tariffs and to DUOS. It is a charge that is variable on a monthly basis and is charged on the actual demand measured in peak and standard periods.

Network Service Provider

A legal entity that is licensed to provide network services through the ownership and maintenance of an electricity network

Network service customer

A network service customer is one that a distributor only provides network services to, i.e. no retail services are provided. Indirect and contestable customers are network service customers of a distributor.

Non-technical losses

Losses that arise from theft or un-metered sales

Notified maximum demand (NMD)

The notified maximum demand (NMD) is the maximum demand notified in writing by the customer and accepted by the distributor, that the customer requires the distributor to be in a position to supply on demand during all time periods. It is normally the capacity reserved by the distributor for a customer in the short term, i.e. the following year, and includes contingency capacity.

Reliability Service Charge

The charge for services provided by NSP to ensure the short-term reliability of supply to customers.

Premium supply Where the customer’s specifications result in equipment to be installed above the least economic cost requirements needed to provide an adequate supply and where the customer specifically contracts for a premium supply. (See also standard supply.)

Rate-rebalancing levy

The rate-rebalancing levy is a separate rate component, in the WEPS, indicating explicit inter-tariff subsidies (subsidies between tariffs) in a transparent manner.

Retail electricity service

A bundled service comprising the purchase of energy, network services for transmission and distribution and customer services.


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Retail tariff The regulated tariff that a retailer (a distributor or a retail entity other than a distributor, as licensed byNERSA) applies to its customers based on its costs and tariff objectives. In order to be as cost reflective as possible, the retail tariff for larger customers should mirror the costs (see WEPS).

Retailer An entity that provides a retail service to a customer. This entity will be licensed by NERSA to provide retail electricity services. A distributor will be required to provide retail services to its franchise customers and a retailer will provide services to its contestable customers.

Service charge The service charge is the fixed charge payable every month. It is a contribution towards service-related costs, e.g. customer service costs.

Standard supply The least-cost economic investment required to provide an adequate supply in terms of NRS 048, NERSA’s power quality directive and in future the Distribution Grid Code (see also premium supply).

Tariff A tariff is a combination of charging parameters applied to recover measured quantities such as consumption and capacity costs, as well as unmeasured quantities such as service costs.

Technical losses Losses incurred over electrical networks due to the characteristics of the physical equipment usually associated with dissipation.

Transmission system

All lines and substation equipment where the nominal voltage is above 132kV.

Transmission use-of-system charges

The regulated tariff charged for the use of the transmission system which includes network, reliability, losses and/or service and administration charges.

Utilised capacity Utilised capacity (UC) is the greater of the customer’s notified maximum demand (NMD) and actual maximum demand registered in all time periods during the previous 12 months. Theoretically, the UC should equal NMD, but at times customers under-notify, resulting in a UC > NMD.


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WEPS A totally unbundled cost-reflective tariff structure comprising energy rates, levies, service and administration charges, transmission network charges, loss factors, reliability service charges anddistribution network charges.

WEPS surcharge A charge levied to compensate for the loss of revenue to a distributor due to the conversion from a standard tariff to the WEPS tariff.

Wholesale electricity service

Unbundled contracting for energy, network usage (including transmission and distribution charges), but excluding customer services.

ABBREVIATIONS AND ACRONYMS

DG Distributed generation

DUOS Distribution use-of–system charges

EPP Electricity Pricing Policy

ERA Electricity Regulation Act

MTS Main transmission station

NERSA National Energy Regulator of South Africa

NMD Notified maximum demand

NSP Network Service Provider

PSO Peak, standard and off-peak

RS Reliability services

SNC Shared Network Service

TNSP Transmission Network Service Provider

TPAF Third-party access framework

TUOS Transmission use-of-system charges

UC Utilised capacity

WEPS: Wholesale electricity pricing system

UOS Use of System Charges

SO System Operator

SRMC Short Run Marginal Cost


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ISMO Independent System Market Operator

PTDF Power Transfer Distribution Factor

kW KiloWatt

TOU Time of Use

KVA Kilo Volt Ampere

NAC Network Access Charge

IPP Independent Power Producer

EPP Electricity Pricing Policy

DOE Department of Energy

Tx Transmission

Dx Distribution


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CHAPTER 1 – INTRODUCTION TO NETWORK CHARGES

1.1 Introduction

The Electricity Regulation Act, 2006 (Act No. 40 of 2006) requires that the transmission, distribution and trading function of electricity supply be separately licensed and that the transmission or distribution function should provide non-discriminatory network access to all users of the transmission or distribution system.

The Electricity Regulations on New Generation Capacity dated 5 August 20091 provides the framework for the procurement of new generation capacity. The pricing of connection and access to the networks are considerations that have to be resolved to give effect to power purchase contracting.

The requirement to issue Independent Power Producers (IPPs) and renewable energy generators with guidelines on the costs involved in network access and transporting electricity necessitates the provision of principles, rules and methodologies of transmission and distribution wheeling, including treatment of network congestion for implementation as prescribed by the Electricity Pricing Policy (EPP).

Use-of-system (UOS) charges are the cost-reflective unbundled tariff structures and rates that recover the costs associated with making capacity available on an electricity network. The use-of-system charges are applicable to generators (entry UOS) and loads (exit UOS) connected to both the transmission system (TUOS charges) and the distribution system (DUOS charges).

This consultation paper seeks to solicit views from stakeholders on the proposed rules. The National Energy Regulator of South Africa (NERSA or ‘the Energy Regulator’) will be making a decision on these rules in July 2011. However, prior to the decision, the Energy Regulator will embark on a due process involving stakeholder consultation. As part of this process, NERSA is requesting stakeholders to comment on the issues raised in this document.

NERSA will collate all comments received, which will be taken into consideration when the decision is made. NERSA will hold a public hearing in the first week of July 2011 wherein presentations may be made by interested and affected parties. The process for the consultation and decision-making is outlined in the table below:

1 The August 2009 Regulations are currently being revised by the Department of Energy. Any

changes to the Regulations will be incorporated in the final framework.


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TIMELINES FOR THE APPROVAL PROCESS OF THE REGULATORY RULES ON NETWORK CHARGES FOR THIRD-PARTY

TRANSPORTATION OF ENERGY

ACTIVITY/TASK DATE

Electricity Subcommittee to consider draft consultation paper

24 May 2011

Publication of the consultation paper (request for comments) on NERSA website

27 May 2011

Closing date for stakeholder comments 27 June 2011

Public Hearing 5 July 2011

Electricity Subcommittee to consider the Draft Reasons for Decision on Network Charges for Third-Party Transportation of Energy

13 July 2011

Energy Regulator’s Decision on Regulatory Rules on Network Charges for Third-Party Transportation of Energy

29 July 2011

Stakeholders are requested to comment in writing on the proposed Regulatory Rules on Network Charges for Third-Party Transportation of Energy.

Written comments can be forwarded to [email protected]; hand-delivered to Kulawula House, 526 Vermeulen Street, Arcadia, Pretoria or posted to P.O Box 40343, Arcadia, 0083, Pretoria, South Africa.

Stakeholders will have another opportunity to present their views on the consultation paper at a Public Hearing scheduled for 7 July 2011. The Public Hearing will take place at the NERSA Auditorium, Kulawula House, 526 Vermeulen Street, Pretoria. Members of the public and stakeholders wishing to attend the hearing or present their views must submit their request to the following email address: [email protected]

For more information and queries on the above, please contact Ms Lehuma Masike or Mr Jeffrey Zwimbane at the National Energy Regulator of South Africa, Kulawula House, 526 Vermeulen Street, Arcadia, Pretoria. Tel: 012 401 4600 Fax: 012 401 4700

The closing date for the comments is 27 June 2011 at 16:00.

mailto:[email protected]



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1.2 Background to the Development of Network Tariffs in South Africa

The current electricity retail tariffs applied in South Africa are ‘bundled’, i.e. tariffs that are charged to customers include all the costs associated with electricity generation, transmission and distribution. The distribution infrastructure cost and the retailing costs (billing, collection and customer management) are included with the other supply costs and packaged as a single tariff to customers. This approach results in tariffs that are not transparent and include various inherent and unmanaged cross-subsidies among users.

The Wholesale Electricity Pricing System (WEPS) was developed to provide a tariff at which electricity distributors and qualifying key industrial customers could purchase their power from an electricity trader rather than from their local distributor.

The WEPS consists of the following major components:

A time and season differentiated energy charge that recovers Eskom’s cost of generating energy.

A transmission use-of-system (TUOS) charge that recovers the cost of losses caused by the transmission of energy, a reliability service charge and an infrastructure charge. The TUOS charge for loads (distributors and qualifying customers) is a geographically differentiated power exit charge. The TUOS charge for generators is a point of connection tariff. The transmission revenue is recovered from generators and loads in a 50/50 ratio.

A geographic, voltage and urban/rural differentiated distribution use-of-system (DUOS) charge formed part of the WEPS in order to reach embedded loads that qualified for the WEPS tariff.

A customer service and administration charge.

The geographic differentiation of the TUOS and DUOS charges for loads is based on a somewhat arbitrarily-prescribed four zones of 0, 1%, 2% and 3% geographic differentiation of charges, depending on the distance of the connection point from Johannesburg in multiples of 300km. The current WEPS TUOS charge for generators is a nodal tariff. Eskom power stations, the international trader and future IPPs pay the TUOS charge to Eskom’s Transmission Division.

In view of the WEPS tariff being a cost reflective tariff, and inherent subsidies in Eskom’s bundled distribution tariffs, an electricity levy and a rural network levy was added to the WEPS tariff for loads to qualifying customers to recover the levies on a c/kWh basis.


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At present, access to distribution networks and use of the system is negotiated between the distributor and the third party. Examples are:

access to Eskom’s distribution network by a generator in order to wheel power to a municipal distributor;

access to a municipal distribution network by a generator in order to wheel power to Eskom; or

wheeling power from one distribution system through another distribution system to supply an embedded customer.

The current situation has to change due to the advent of electricity distribution function as a separately regulated activity from the electricity trading (retail) function and the requirement for non-discriminatory access to the distribution network to allow bi-lateral power trading and access to non-Eskom power generation anywhere in the transmission or distribution system.

1.3 Electricity Network Pools in South Africa

The electricity networks currently consist of the following network pools:

1.3.1 Transmission network

Eskom Transmission consists of all networks operating at above 132kV and all interconnections with neighbouring countries. The transmission system provides the following power entry and exit connection points:

Power entry points

o Centrally-dispatched Eskom Generators (transmission lines with a distribution voltage connecting generators to the transmission system are included in the definition of the transmission system)

o Power Imports

o Eskom Distribution (where the distribution voltage interconnection between transmission connection points results in power flowing back to the transmission system)

Power exit points

o A few very large loads connected directly to the transmission system

o A few large municipalities connected directly to the transmission system

o Eskom Distribution


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o Power Exports

1.3.2 National or regional distribution

The networks operating at distribution voltages above 33kV would fall into this network pool. These networks could be seen as sub-transmission.

1.3.3 Distribution network

The definition used in South Africa for a distribution network includes all networks operating at a voltage level of 132kV or below, with the exception of certain lines used specifically as part of the transmission system. Distribution use-of-system pricing relates to the regulatory asset base associated with the use of these networks.

1.3.4 Distribution network charges

Other charges that distribution businesses may make in addition to distribution use-of-system charges include:

Connection charges.

Charges for alterations to the service lines or distribution networks requested by customers, other utilities, highway authorities, etc. Such charges would normally be expected to cover the full costs of such works, including an appropriate allowance for on-going maintenance of the diversions or alterations.

Charges to customers that specifically request increased reliability or other non-standard supply arrangements. These charges should also cover the full amount of the additional costs of providing the supply, including on-going maintenance costs.

Other charges relating to costs outside the regulatory asset base.

In addition to the charges for using the networks for power distribution (which may include fixed charges, capacity, energy-related and reactive power elements), distribution businesses also need to make charges for the provision of metering services – including the provision of meters and the data collection services associated with obtaining, verifying and delivering the metering data to users.

A further issue relates to the energy (technical) losses that occur in distribution networks. Distribution losses may be treated as part of the energy costs in the market, so that retailers or generators settle on the basis


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of regulated distribution loss factors2, calculated by the distributors. Alternatively, the distribution businesses may bear the cost of the losses and recover the costs within the DUOS structure. In the former case, retailers and generators bear the risks associated with uncertainty in the determination of losses whereas in the second case, the distribution businesses bear this risk. There are advantages and disadvantages associated with both approaches.

1.4 Scope, Objectives and Requirements

1.4.1 Scope of the Consultation Paper

This consultation paper sets out the principles associated with DUOS and TUOS charges payable by all customers (loads and generators) that make use of the capacity of a distributor’s system, including the recovery of transmission charges.

DUOS charges are raised to recover costs associated with the wires portion of a distributor’s business. However, since network charges are used as a vehicle to subsidise specific customer categories, the consultation paper deals with subsidies and levies associated with the provision of network services. The levies to enable subsidies may be payable by any electricity consumer in South Africa.

DUOS charges for loads and generators will be determined based on each distributor’s costs as allowed by NERSA.

1.4.2 Objectives

The objectives of the DUOS and TUOS charges are:

Promotion of economic efficiency: The central objective of an efficient network-pricing regime is the promotion of efficiency in the use, operation of and investment in the network, so that costs are minimised in the long run.

Promotion of non-discriminatory access: To promote the ability of customers to contract independently with independent power producers and non-discriminatory access to and use of the transmission and distribution networks to generators.

Cost reflectivity: Prices should reflect the cost of providing a service as far as possible based on the relative to the utilisation of the networks.

Non-discrimination: The same electricity network price should apply to all users of the network and be related to the utilisation of the networks.

Transparency: It should be clear to users how network prices are determined.

2 Generally, simple fixed factors are used to represent the average losses incurred. However,

losses vary with load (square law relationship); with ambient temperature; and a proportion of the

losses in distribution transformers are constant whenever the transformer is energised.


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Revenue recovery of service providers: The revenues recovered through the charges should be sufficient to sustain the transmission and distribution businesses and allow for appropriate expansion of the networks.

Affordability: The cost of these services should be affordable to the majority of users and potential users.

Uniformity, simplicity and predictability: Prices must be simple, transparent and readily understood. Many tariffs should be avoided and the number of discretionary rulings should be minimised. Customers should also be protected from unusually large fluctuations in charges.

1.5 Network Tariff Requirements

The following are requirements of the Electricity Pricing Policy3 of the Department of Energy (DoE): Policy No. 3: Transparency and Unbundling The customer bill must comply with NRS047 Policy No. 5: Wheeling

a) Fair and non-discriminatory access to and use of networks to all users of the relevant networks.

b) The full cost to operate the networks is reflected in the various connection and use-of-system charges and, therefore, no additional charges for wheeling of electricity will be levied unless the wheeling action introduces incremental costs.

c) Any incremental wheeling costs associated with a specific wheeling transaction and its fair share must be recovered as a connection charge.

d) Wheeling of electricity can only be permitted if the action complies with all technical, safety and commercial requirements.

e) A methodology for transmission and distribution wheeling, including the treatment of network congestion, must be developed by NERSA.

Policy No. 17 – Transmission prices

a) Transmission tariffs must be unbundled (e.g. charges for: TUOS, line losses, customer services and connection) to reflect more accurately the cost of supply.

b) Connection charges must be fair and calculated in accordance with a standard to be approved by NERSA.

3 The South African Electricity Supply Industry: Electricity Pricing Policy GN 1398 of 19 December 2008


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c) The transmission tariff structure must reflect the cost of supply and could consist of a combination of capacity, energy loss factors and fixed charges.

Policy No. 19 – Transmission cost apportionment

a) Transmission network costs must be apportioned 50/50 between generators and customers to more accurately reflect the cost of supply.

b) Transmission losses costs will be allocated directly to loads.

c) Transmission service and other costs must be allocated rationally between loads and generators and must reflect the cost to provide the service.

d) The apportionment between generators and customers must be reviewed from time to time to ensure compliance with regional approaches in order not to disadvantage South African-based generators.

Policy No. 20 – Transmission price structure

a) The current transmission geographic differentials for customers must remain until it is succeeded by an approved redefinition of geographic differentials.

b) The transmission licence holder, DoE and NERSA must evaluate the redefinition of geographic differentials for customers assessing the price stability, comparing the current generation mix with that foreseen in the next 10 years.

c) The transmission licence holder, DME and NERSA must investigate different options and adopt the most appropriate method for allocating costs between generators.

Policy No. 22 – Wholesale traders

a) Wholesale energy and transmission prices must be available on a fair and non-discriminatory basis to all qualifying wholesale electricity traders.

b) DoE, in consultation with NERSA, must determine qualification criteria for wholesale traders and NERSA must determine implementation guidelines.

Policy No. 33 – Geographic differentiation

a) Tariffs charged to customers on the network will be cost-reflective within the relevant electricity utility.

b) No geographic differentiation based on location will be applied within the area of a licensee except for farms (low density agriculture) and supplies associated with lower density.

Policy No. 53 – Rural subsidies

a) Cost of supply studies must be undertaken featuring pooling strategies which separate significant groups of customers that differ significantly from other


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customers. One such category which must be treated separately relates to supplies on farms.

b) The current cross-subsidy mechanism for supplies on farms must be continued for the time being and the impact shall be shown as a transparent levy in electricity bills where practical.

c) The DoE must undertake a study to consider the introduction of alternative subsidy/cross-subsidy mechanisms to address the challenges relating to farm network replacements.

A regional (RED) electricity levy applied at the regional (RED) level and thus managed by the RED.

A national electricity levy applied at the wholesale level and thus managed by the DoE or an agent of the DoE.

The requirements of the electricity pricing policy largely confirm the structure of the current TUOS and DUOS tariffs in WEPS. The DUOS charges in WEPS have only an exit component to serve loads. The TUOS tariff has both an entry component to serve generators and an exit component to serve loads. Since Eskom’s generation costs, which include the TUOS charge to generators, are accumulated in the WEPS energy price, the nodal differentiated point tariff for entry TUOS charges to generators is averaged out and does not impact the Eskom generators. This would not be the case for non-Eskom generators making use of the Transmission or Distribution system. Since the Distribution network cost of Eskom is allocated 100% to loads (exit points), it would be appropriate to not allocate any network costs to generators (input points) to the network. This would be aligned with EPP Policy No. 5(b) which requires that ‘no additional charges for wheeling of electricity will be levied unless the wheeling action introduces incremental costs.

1.5.1 National vs. regional network tariffs

The requirement of EPP Policy No. 33(b) that ‘No geographic differentiation based on location will be applied within the area of a licensee except for farms (low density agriculture) and supplies associated with lower density’ has implications for the achievement of the cost reflectivity, affordability and economic efficiency objectives. The policy implies that Eskom will have a national DUOS tariff differentiated by voltage level and by low density (rural) and high density (urban) areas, while other distributors will have localised network tariffs. If regional electricity distributors are established, the DUOS tariffs of all electricity distributors would have to be adjusted in accordance with the cost of the network service within the regional boundaries.

In municipal distribution areas there will be no geographic differentiation of network tariffs. This would have the effect of different network tariffs in the same geographic


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area depending on whether the customer is connected to the local Eskom network or the municipal network.

Consultation Question 1:

(a) Should the Eskom network tariffs be designed to recover the cost of network operations and losses within the boundaries of regional geographic areas or should the current national geographic differentiation of 0% to 3% be retained.

(b) Should municipal distribution network charges that are different to the Eskom network tariffs be allowed?

(c) What other options for designing network tariffs should be considered by NERSA?

1.5.2 Pooling of networks

The EPP Policy 33(b) requires that the network prices for farms (low density agriculture) and supplies associated with lower density networks be differentiated from high density networks. To implement such differentiation would require that the distribution networks of an entity is pooled into a regional component (medium to high voltage distribution) a local (reticulation voltage) urban component and a local (reticulation voltage) rural component. Such differentiation will ensure that a distributor with mainly reticulation voltage rural supplies receives the same network charge as what is charged to a neighbouring rural network of a distributor who owns the regional distribution system.

Consultation Question 2: Should rural and urban reticulation networks be ring fenced from regional distribution networks to allow non-discriminatory network tariffs to be charged to reticulation voltage network users irrespective of who owns the regional networks?

1.5.3 Tariffs structure for bilateral agreements

In order to meet the objective of promoting independent generation, the following requirements would have to be met:

Responsibility for metering and settlement of trading volumes must be established.

Trading transaction costs should be kept low by allowing the tariff and connection agreement to give access to the whole interconnected network system.

Network tariffs should be independent of the commercial trading arrangements.


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All money paid for access to the system should be collected from the users at their point of connection.

The distribution service provider should buy all losses and recover it in the network charges.

The DUOS should signal the marginal cost of network (transmission and distribution) usage. Marginal costs consist of the physical losses from power flow in lines and transformers; constraints causing ‘out of merit’ generation; and the cost of additional capacity to reduce losses and constraints.

Costs not collected through the short run marginal cost (SRMC) component of DUOS should be collected through a residual tariff component.

Qualifying customers should be free to go into bilateral arrangements with any generator.

Consultation Question 3: Should network tariffs be designed to facilitate bilateral trade between generators and traders and between generators and qualifying customers.

1.6 General Market Rules

The general market rules provides the context within which the TUOS and DUOS charges will be applied.

1.6.1 Licensing and ring-fencing

Currently, Transmission is licensed for the ring-fenced functions of Network Service Provider (NSP) and System Operator (SO). The cost of Transmission including its purchase of losses and ancillary services is charged out to loads (including power exports) and generators (including power imports) using the TUOS charges.

Currently, Distributors are licensed for the bundled activity of a wires service and a retail service. In future, the Distribution (wires) and Retail functions of electricity supply will be separately licensed as required by the Electricity Regulation Act.

Where the activities are licensed to the same entity, the operating cost of the distribution and retail activities must be ring-fenced.

All load customers served by a particular distribution system will be charged the same exit DUOS charges.

Regional and local distribution systems will be identified to be separately ring-fenced in order to differentiate between rural and urban reticulation services. The regional systems will be Eskom Distribution Regions which are organised into geographic areas and Metro transmission networks


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operating at voltages of above 33kV. Local networks will be those operating at 33kV and below. Eskom and the Metros will thus have both Regional and Local networks.

Distributors are licensed to provide a connection and network service to all connection points in its distribution area.

Distributors will be licensed to provide a metering service to all connection points in its distribution area. This service could be contracted out to metering service providers, but the Distributor would remain accountable in terms of the licence.

1.6.2 Network service vs. retail electricity service

Non-technical losses due to inaccurate or insufficient metering, interference with metering and illegal connections to the distribution network will be borne by the metering service provider (the Distributor).

The non-payment risk will be carried by the electricity trader serving that customer.

The Distributor will determine the charges; for each delivery point (exit point) an exit charge and each entry point an entry charge, irrespective of who is doing the trading (buying or selling) electricity in the area.

The Distributor will charge retailers and other entities operating under a trading licence for each of the connection points used for trading. The Retailer and other trading entities will recover the DUOS charges via their retail tariffs.

The Distributor will provide the appropriate metering of connection points to the relevant retailers and traders.

The Retailer is required to show the DUOS charge as a separate charge in the end user account.

1.6.3 New generation capacity generators

In accordance with the provision of Section 34(1) (c) and (d) of the Act, the Minister may designate the buyer of electricity in relation to a new generation capacity project.

The designated buyer is expected to operate as a retailer under a trading licence issued in accordance with Section 4 of the Act.

Under the Distribution and Transmission Agreement, the Seller as the Customer of the Grid Provider will be required to pay the regulated Use-of-System Charges.

The Customer will be permitted to recover its Use-of-System Charges from the Buyer under the PPA through supplemental pass-through payments.


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1.6.4 Commercial arrangements

Retailers and qualifying customers purchase their power from an Electricity Wholesaler. The Wholesaler is the entity that purchases power from generators (both Eskom, IPPs and power imports). The wholesaler could be a single buyer or the Independent System Market Operator (ISMO) of the future.

The Transmitter and Distributor purchase their system losses from the Electricity Wholesaler.

The Generators and Distributors purchase its use of the Transmission system from the National Transmitter. This includes losses charges by the Transmitter to the Distributor.

The Generators and Distributors purchase reliability services from the National System Operator.

The Distributors charge their network users (loads and generators) a bundled network service and losses charge.

1.6.5 Non-discrimination

No differentiation between traders operating in the area of the distributor should occur. The net effect of trading on the losses in the distribution system will be charged to network users.

Consultation Question 4: Stakeholders are requested to comment on the appropriateness of the proposed market rules, in particular:

a) The allocation of responsibilities to the Distributor and the Trader (Retailer)

b) Should billing for network services be a separate account from the distributor to each user of a connection point or should it be billed to the relevant Trader?

c) Who should provide the metering service?


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CHAPTER 2 – TRANSMISSION USE-OF-SYSTEM (TUOS) CHARGES

The cost of Transmission is recovered through the Transmission Use-of-System charges from both generators and loads. In Eskom’s case, this cost is equally split between the two, i.e. on a 50/50 basis. Costs are recovered in this manner because the generators need the transmission network so that they can supply the loads, and the loads need the transmission network to gain access to the energy. TUOS charges consist of the following components:

TUOS network charges

TUOS losses charges

Reliability service charges

Administration and service charges

The TUOS charges apply to all connection points to the main transmission system (MTS). At points where distribution network services are connected to the transmission system the TUOS exit charge is carried forward into the distribution charges as an embedded TUOS charge. The applicable charges are discussed below.

2.1 Network Charge (Transmission Infrastructure Charge)

The transmission infrastructure charges are designed to cover the cost of transmitting energy from the generators to the Main Transmission System (MTS), from where Distributors and customers are supplied. This charge is linked to the long-term network capacity required by the customers. Consequently, the R/kVA charge is based on the greater of the customer’s Notified Maximum Demand (NMD) or his actual recorded maximum demand in the preceding 12 months. The network charges (transmission infrastructure charge) applicable to loads and generators connected to the transmission system are detailed below:

2.1.1 Transmission (Tx) infrastructure charge for loads

The Tx infrastructure charge for loads is differentiated into two components:

A Tx network charge, which is a geographically differentiated charge aimed at recovering the cost of the transmission system, 220kV and higher. The geographic differentiation will be in line with the normal 0% to 3% geographic differentiation currently used for retail tariffs.


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A Tx connection charge, which is a voltage-differentiated charge aimed at recovering the cost of the substation equipment where the customer is connected (i.e. line and transformer bays and transformers).

Transmission network infrastructure charge for loads is charged in R/kVA per month. The charge is based on the greater of the customer’s NMD or the actual recorded maximum demand over the preceding 12 months. The charge is differentiated in four zones based on the distance of the load in kilometres from Johannesburg, as follows:

Zone 1 – 0 to 300km (no surcharge)

Zone 2 – 301 to 600km (1% surcharge)

Zone 3 – 601 to 900km (2% surcharge)

Zone 4 – >900km (3% surcharge) The charges are calculated such that 50% of the infrastructure cost of the transmission network service provider is recovered by applying the charge including the surcharge.

Consultation Question 5: Stakeholders are requested to comment on the proposed methodology to determine transmission infrastructure charges for loads.

2.1.2 Transmission Infrastructure charge for Generators

Generators are charged in R/MW per month to recover the remaining 50% of the cost of the transmission network service provider. The charge is based on the installed MW sent out capacity of the generator. It is proposed that the charge be differentiated into six tariff zones based on the concentration of power generation in South Africa as per the table below:-

Zones Generators

CAPE Acacia, Ankerlig, Gourikwa, Koeberg, Palmiet, PortRex (Future renewable energy generators)

KAROO Gariep, Van der Kloof (Future renewable energy generators)

KZN Drakensburg (Future Ingula)

MPUMALANGA Apollo, Arnot, Camden, Duvha, Hendrina, Kendal, Komati, Kriel, Matla, Majuba, Tutuka

VAAL Grootvlei, Lethabo

WATERBERG Matimba, (Future Medupi, Coal3, Coal 4)

Table 1: Six generator zones


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Figure 1: Six Generation pricing zones

The zones are developed using the transmission charging principles as prescribed in the Grid Code. Figure 1 presents a graphical view of the six pricing zones. The network charges (transmission infrastructure charge) for generators are calculated based on the Power Transfer Distribution Factor methodology (PTDF) as described in the South African Grid Code, tariff code section. The distribution PTDFs provide an indication of the relative locational value of new generation. These factors are converted to tariffs in Rand per kW injected into the zone by multiplying the factor with 50% of the cost of the transmission network service. Using this methodology, the Cape and Karoo zones currently has negative network charges due to the benefit associated with adding generation in these zones.

Applying the charge on the basis of installed capacity would cause the cost of using the system to be unrelated to the extent that the system is used (actual production), but only to the connection capacity.

Applying the charge on the basis of actual production (maximum power or energy sent out) would result in unpredictable and volatile charges in the zones.

Another option would be to base the charges on the dependable capacity of generators rather than the installed capacity.

Consultation Question 6: Stakeholders are requested to comment on the following aspects of the transmission network charge:


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(a) The proposed zones for determining geographically differentiated generation network tariffs.

(b) The basis on which network tariffs are charged to generators, should it be a capacity, maximum hourly production or an energy charge?

(c) Should there be different charges for different types of generators?

An alternative way of structuring the network charges would be to adjust the Cape and Karoo network charges to zero and to reduce the network charges in the zones with positive network charges.

Generation Zone

Typical cost reflective charge for 2010/11

Charge with negative prices

set to zero

CAPE -2.18 -

KAROO -1.71 -

MP 5.56 5.26

KZN 1.6 1.52

VAAL 4.63 4.38

WATERBERG 5.85 5.53

AVERAGE 4.48 4.48

Table 2: Transmission network charge R/kW per month

The charges will be calculated annually based on the allowed revenue of the Transmission network service provider and the installed generation capacity in the proposed zones. The relative value of the charges is expected to change as the installed capacity in the zones changes.

The motivation for setting the negative charges in the Cape and Karoo zones to zero is that these zones will have wind generators and has gas turbines which operate at a low load factor since wind generation is not always available. The question then arises of whether or not these generators should be rewarded for their impact on network strengthening and reduction of losses.

Consultation Question 7: Stakeholders are requested to comment on the following:

a) Is it appropriate to have negative network charges for generators that operate intermittently (gas turbines, wind generators) when its output cannot be relied on?

b) Is it appropriate to charge based on installed capacity? Could other parameters such as maximum production or average energy produced be considered?


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2.1.3 Reliability Charges to loads and generators

The general principle is that all loads and generators should be charged for reliability services, based on the fact that the security of the network is a requirement for the generator as a user of the network. The cost of reliability services is based on the total energy consumed in the network, and this cost is passed on to all customers in the retail tariffs. It is proposed that the reliability charge for loads and generators be the same, and be the published WEPS tariff. The tariff would be based on the allowed revenue of the System Operator (including the cost of ancillary services) divided by the total of energy flow into and out of the transmission system.

Consultation Question 8: Stakeholders are requested to comment on the proposed approach to recovering the cost of reliability services from traders and retailers.

2.1.4 Service and administration charges to loads and generators

Where a Transmission Network Service Provider (TNSP) is required to manage connection agreements, the wheeling of energy, metering, settlements and billing adjustments, the costs associated with customer service and administration will be recovered from the generator.

In order to ensure the recovery of associated service and administration costs, the following approach will be taken:

The service and administration charges will be the associated WEPS charges.

The service charge applies to each electricity account, payable every month, based on a daily tariff rate (Rand per day).

The tariff is differentiated based on the sum of the monthly maximum power import (entry) or export (exit) capacity for all points of connection linked to the account.

The service and administration charges applicable specifically to generators will be calculated and submitted for approval to NERSA when the administrative and service costs associated with generators have been determined.

Consultation Question 9: Stakeholders are requested to comment on the service and administration charges for generators. a) Should there be capacity differentiated charges? b) Should there be a choice of the required service level?


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2.1.5 Losses charges for loads and generators

A load or generator connected directly to the Transmission network will be charged for losses according to the WEPS. In reconciling cross-border energy, all energy measured will be compensated for losses up to the South African border. Transmission recovers the cost of the resistive losses in its grid. The cost of losses is charged based on calculated average loss factors for all loads and generators. The cost of the losses relates to the losses incurred to service a specific customer class (i.e. loads or generators).

The loss factors for loads are calculated to be in line with the current 0% to 3%

geographic differentiation applicable to Eskom’s retail tariffs. The loss factors for generators are calculated for the six generator zones.

The loss factors change as the transmission system develops and as new

generators and loads are added to the transmission system.

The actual consumption of loads and production of generators in each time period (peak, standard and off-peak) are multiplied by the relevant loss factor to recover the cost of losses at the WEPS time-of-use (TOU) rates applicable to each time period. Losses = Delivered energy (kWh) x (Loss-factor –1) Since the WEPS rates are TOU differentiated, it stands to reason that these measurements and calculations have to follow the same TOU periods. The cost of these losses will be charged at the regular time differentiated WEPS energy rates.

Cost of Losses = Cost of lossest = Lossest (kWh) x Pt (c/kWh)

Cost of Losses = {Delivered energyt x (Loss factor –1)} x Pt

Where t = the appropriate peak, standard or off peak time period and Pt = WEPS energy price for PSO time periods.

Consultation Question 10: Stakeholders are requested to comment on the proposed approach to recovering the cost of transmission losses.

2.2 Transmission Connection Charges

Transmission connection charges will be based on customer (load or generator) specific costs, i.e. dedicated costs incurred for the benefit of the customer. In the event where more customers connect at the same point, where assets were


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previously determined to be customer specific and were paid for through a connection agreement, the new customer(s) will be charged for the use of such assets on a pro rata basis compared with the original customer. The original customer will then receive a rebate based on the payment of the new customer(s). An early termination guarantee for shared assets, i.e. upstream reinforcements, will be raised for wheeling generators.

Consultation Question 11: Stakeholders are requested to comment on the proposed approach to recovering the transmission connection cost and the raising of an early termination guarantee.


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CHAPTER 3 – DISTRIBUTION USE-OF-SYSTEM CHARGES

3.1 DUOS Charges for Loads

The DUOS charges consist of the following components

DUOS network charge

DUOS losses charge

Reactive energy charge

Customer service and administration charge

3.1.1 Structure of DUOS tariffs

The following are suitable structures for distribution use-of-system tariffs. Note that the tariff structures are consistent with those already used for retail (end-use) tariffs, thus no additional metering is involved. The DUOS tariff structure is simply separating out the ‘wires’ costs from the existing bundled tariffs. In doing so, however, it ensures that the overall tariff structures (wires and retail element) are cost reflective. For those customer groups with kW demand metering (including the very large customers that have half-hourly metering installed), a two-part DUOS tariff as follows:

A fixed (e.g. monthly) charge to cover the costs associated with the provision of metering services (unless these are to be regulated separately).

A demand charge in Rand/kW or Rand/KVA, based on the highest maximum demand registered in a moving 12-month period, or the agreed capacity, whichever is higher.

A usage-dependent charge, in cents/kWh, which may vary between different time-of-use, depending on the metering installed.

For those customer groups with only kWh metering, the charges would need to be rolled up into the usage-dependent kWh charges, but may also include a fixed charge for metering services. This will ensure that the structure of distribution use-of-system charges follows the existing tariff structure of Eskom and the Municipalities, thus avoiding the cost of additional measurement.

3.1.2 Application of DUOS tariffs

Distribution charges would to apply to all retailers, based on their customers’ usage. The data from the customer metering that is used by retailers to bill their customers also serves as a basis for distribution use-of-system charges. Because of the timing between actual usage and data collection,


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the settlement of such charges needs to accord with the practicalities of the data collection and data processing involved. It is assumed that distribution businesses will be responsible for this data collection, as well as maintaining the associated metering. Distributors will require a system for billing retailers and will need to assign a retailer to each customer. However, since retail contestability is to be confined to a relatively small number of customers, mostly connected directly to the transmission system, this should be straightforward as all captive customers will be supplied by the local Distributor, albeit under a separate (retail) licence. For captive customers the ‘billing’ could take the form of a simple accounting transaction within the books of the company between the separate accounts for retail and distribution. It could be based on the regulatory allowance used for price/revenue controls, instead of the specific DUOS tariffs.

3.2 DUOS Network Charges Component for Loads

The following rules are proposed for DUOS network charges:

The DUOS charge will be based on the cost per kVA demand, excluding connection charges and upfront contributions.

The DUOS charge will be based onnotified annual maximum demand (NMD)

The DUOS exit network charge for loads (all connection points where power flows out of the network, including flows to other distributors or the transmission system) is split into two charges:

o DUOS Network access charge in R/kVA on the highest utilised capacity (highest of actual demand over 12 month period and notified MD); and

o DUOS Network demand charge. Charged on the highest demand measured in a billing period and may be time differentiated.

The DUOS charges will be differentiated according to the distributor’s voltage and topographical (rural/urban) categories. These categories will be determined by each distributor, based on a logical and justifiable categorisation that avoids unnecessary cross-subsidisation between customers.

The notification of demand is an important factor determining the network charges for the distributor. The distributor will be required to publish a set of rules that will govern the notification of demand by customers.

Consultation Question 12: Stakeholders are requested to comment on the proposed approach to recovering the cost of distribution network services from traders and retailers.


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3.3 DUOS Losses Charges for Loads

The following rules are proposed for DUOS losses charges:

The cost of electrical losses will be recovered as a function of (a) the appropriate loss factors for the relevant voltage level and (b) the distributor’s cost of energy purchases on a time-of-use basis.

The loss factors will be differentiated according to the distributor’s voltage and geographic categories.

The distributor will purchase from its supplier (the Electricity Wholesaler) the energy that is lost in its networks while transporting this energy to the customer. This cost will be recovered by determining the amount of energy losses, multiplied by the energy-purchasing rates of the distributor.

The distributor will be responsible for all losses flowing through its system and will recover it from all loads connected to its system as part of the DUOS exit charge.

The energy losses in the distribution system are determined by measuring the energy used by the customer, i.e. the delivered energy. This energy, multiplied by the distribution loss factor for the appropriate transaction voltage, will be the calculated energy losses in the distribution system. These loss factors are determined on the basis of the estimated losses associated with particular networks of the distributor and may differ from one distributor to another, depending on the density of customers and the type of networks installed. The formula to determine distribution losses is:

Total distribution losses = delivered energy x (distribution loss factor-1)

Losses will be priced at the wholesale electricity purchase price that the distributor is charged for losses incurred.

The wholesale power purchase rates are differentiated according to the time-of-use, the measurements and calculations of losses will follow the same time-of-use periods.

In calculating the cost of losses, both the transmission and distribution loss factors have to be considered and will be charged at the purchase energy rates as follows.

Charge for total losses = {Delivered energyt x (distribution loss factor x transmission loss factor-1) x Pt}

Where:

t = the appropriate peak, standard or off-peak time period and


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Pt= Purchase energy price for each PSO time periods.

3.4 Reactive Energy Charges

A reactive energy charge will be included in the DUOS charge in accordance with the distributor’s pricing signals required for reactive energy costs.

3.5 Customer Service and Administration Charges

The cost of customer service is a fixed (e.g. monthly) charge to cover the costs associated with the provision of metering services. This cost will be charged by the Distributor to each point of connection.

3.6 DUOS Charges for International Customers

The regulated DUOS charges will apply to all international connections for the use of distribution networks inside the South African borders, with the exception of the rate-rebalancing levy.

International customers will not be subsidised by South African customers, nor will they be required to contribute to any explicit subsidies (i.e. the rate-rebalancing levy) in the DUOS charges. However, the implicit subsidies, caused by the averaging of costs in tariff design, will remain applicable.

3.7 DUOS Charges for Generators

The Distribution Use-of-System charges will comprise of connection charges, network charges, network charge rebate, reliability services charges (same as criteria for loads) and service and administration charges (same as criteria for loads). The charges are described in the details as follows.

a) Network charges Generators embedded in the distribution network will only impact the cost of distribution (network usage and losses) in exceptional circumstances because the nodes where embedded generators are connected are predominantly demand dominated. It is further not considered prudent to provide a credit to embedded generators for reducing distribution losses and enhancing network reliability because the generation is not always in service.


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Currently all Distribution costs are allocated against the capacity used and reserved by loads only.

Generators connected at sub-transmission level (66kV to 132kV) may not be at demand dominated nodes and different views exist about network and losses charges at this voltage level. These views are:

a) That no network or losses charges are to apply, because the minor costs triggered by these generators are paid by load customers.

b) That a network charge and losses charge as currently determined for loads are to be charged. These charges are voltage differentiated. The benefit of reduced distribution losses is assumed to be the inverse of the cost of losses based on the current Eskom published loss factors for load customers. The network charge to generators would be cost reflective charges, which are about 70% lower than the network charge for loads.

c) That the network charge as in (b) be rebated for savings in losses. This would ensure that the charge for network and losses do not become negative.

d) That the same charges and zones as applicable to transmission connected generators be used for sub-transmission connected generators.

Administration and service charges are payable by embedded generation customers in the same way and the same rate as for load customers. Reliability service charges would apply to embedded generators since these generators would impact the voltage control requirements of the distributor.

Consultation Question 13: Stakeholders are requested to comment on the charges for distribution connected generators.

In the case of co-generators that are both importers and exporters of energy, the network charges applicable to loads will apply to the net load imposed on the distribution network.


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b) Reliability charge

The general principle is that all generators connected to the Distribution network should be charged for reliability services, based on the fact that the security of the network is a requirement for all users of the network. The cost of reliability services is based on the total energy consumed in the network, and this cost is passed on to all customers in the retail tariffs.

c) Service and Administration charge

Where a Distributor is required to manage connection agreements, the wheeling of energy, metering, settlements and billing adjustments, the costs associated with customer service and administration will be recovered from the generator.

In order to ensure the recovery of associated service and administration costs, the following approach will be taken:

i) The Distributor will raise service and administration charges based on the size of the plant. These charges will contribute to the cost of the management of wheeling arrangements, metering, settlement and billing adjustments.

ii) The service charge applies to each electricity account, payable every month, based on a daily tariff rate (Rand per day);

iii) The tariff is differentiated based on the sum of the monthly maximum power import (entry) or export (exit) capacity for all points of connection linked to the account.

d) Losses charge

The DUOS charges for an embedded Generator will take into account the generator’s impact on the distribution losses. In the case of co-generators that are both importers and exporters of energy, the network charges applicable to loads will apply to the net load imposed on the distribution network.

Consultation Question 14: Stakeholders are requested to comment on the charges for distribution connected generators. a) Should network charges be raised for medium voltage (11 and 22 kV) connected generators?


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3.8 Distribution Connection Charges for Generators

All Generators connected directly to the Transmission network will be charged connection charges in terms of the Transmission Grid Code.

In line with the Distribution Code, Embedded Generators will pay connection charges based on the following:

Charges will be raised as for loads where there is export onto the network, i.e. dedicated costs plus a shared network cost (SNC) based on export capacity.

A standard supply option will be provided. Any additional costs, dedicated or upstream, to accommodate above-standard customer requirements will be for the customer’s account.

No capital allowance will be given while no use-of-system network charges are raised.

All actual upstream shared costs will be recovered through the SNC, where applicable, or in the rate base.


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CHAPTER 4 – POWER WHEELING AND CONTRACTUAL MATTERS

4.1 Charges for distribution connected generators

Several transactions take place for the supply of electricity from generators to loads (customers). The generator will contract with the network provider, i.e. Eskom or the Municipality, to provide network services as well as a contract with the entity purchasing the energy through a PPA. This purchasing entity may be Eskom, a third party, or own generation. If the energy is sold to a third party, the electricity bill of the third party, that is, the customer receiving the energy, must be adjusted to take into account the wheeled energy. This is done in terms of a supplementary contract between Eskom and the customer receiving the wheeled energy. The customer will pay the standard tariffs associated with the cost of delivering the energy. Generators, whether they sell energy to Eskom or wheel energy to third parties, will pay the same Distribution Use-of-System charges, based on their export capacity and energy and the service provided to the generator. Customers that receive wheeled energy from a non-Eskom generator will pay the same standard tariff charges, based on their capacity requirements and the amount of energy delivered over the network to their point of supply, as any other customer. Generators embedded in the distribution network will only impact the cost of distribution (network usage and losses) in exceptional circumstances because the nodes where embedded generators are connected are predominantly demand dominated. It is further not considered prudent to provide a credit to embedded generators for reducing distribution losses and enhancing network reliability because the generation is not always in service.

4.2 Connection and Use-of-System Agreement

In accordance with the provisions of the Grid and the Distribution Code, the customer shall apply in writing to the relevant network service provider (NSP) for connection to the network system, as well as for the right to use the network system. Subject to the provisions of Transmission Licence or Distribution Licence, the NSP may enter into agreements with legal entities licensed to undertake the generation of electrical energy for the connection to and use of the Transmission or Distribution System.

The Connection and Transmission or Distribution Use-of-System Agreement will set out the terms and conditions upon which:


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a) the NSP and/or the Customer shall undertake the connection works;

b) the NSP shall permit the Customer to use the Transmission System in connection with its licensed generation undertaking; and

c) the Customer shall pay to the NSP the Connection Charge and TUOS or DUOS Charge.

4.3 Wheeling of Energy (Third-Party Access)

Wheeling of energy, i.e. access between a generator and a third party (load) to facilitate the trading of energy, is allowed, subject to the generator receiving its approvals from NERSA to trade (sell to a third party) and signing the network service provider’s Connection and Use-of-System Agreement. The account(s) due to third-party access will be reconciled in terms of the rules on the reconciliation of accounts (refer to next section) and the third-party access framework.

a) Wheeling arrangements A generator may enter into the following arrangements for the sale of energy to a third party:

Sell to remote Consumer or Consumers through Eskom Network Service Provider.

Sell to a directly connected Consumer, but not export onto Eskom networks.

Sell to a municipal customer from a generator connected to Eskom’s distribution network.

Sell to an Eskom customer/Eskom from a generator that is connected to a municipal distribution network.

b) Basic principles of third-party access framework (TPAF):

A generator has the same rights of access to the network as a load, subject to the Code (Distribution and Grid Code) and Distribution and Transmission rules.

A Consumer (either an existing Eskom customer or a new customer connecting either to an Eskom network or a municipal network) has the right to purchase energy from a third-party generator.

The Wholesale Administrator will administer the third-party access mechanism, including the balancing component of the mechanism.


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The network owners (Distribution Network Owners and Transmission Network Owners) will not be liable for the effects arising from the failure of their networks to deliver energy contracted under power purchase agreements between consumers and generators. The standard liability for direct damages will apply.

Energy purchased by a consumer through a power-purchase agreement with a generator hosted on an international network is expected to be consumed by the Consumer and may not be traded to a third party (other than Eskom).

Third-party access will be provided to South African generators, provided that they are licensed by NERSA to generate and trade (which may include bilateral contracting).

The following assumptions have been adopted for the purposes of this framework. These assumptions may be amended in the course of time, leading to changes in the rules set for the TPAF:

A Generator will not connect at low-voltage (<1 kV) and will connect either to an Eskom Distribution network (as an embedded Generator) or the Eskom Transmission network. The capacity of embedded generators will not exceed 300MW. Though this ceiling is somewhat arbitrary, it is laid down as a signal to deal with the additional risk on Eskom in providing back-up supply to consumers due to the failure of generators that are not centrally dispatched.

The consumer with whom the distributor will have the third-party arrangement must be a network customer of the distributor. The reconciliation of energy will occur between the sending and the receiving distributors.

The System Operator may contract with generators to provide reserves and other ancillary services in accordance with the System Operator’s normal procurement procedures for ancillary services.

All TPAF allocations shall be made on a calendar month basis. Even if consumers and generators have different billing months with the distributor, the non-Eskom Generator send-out energy will be metered on a calendar month basis and allocations made at the end of the calendar month. Consumer accounts will be credited with the allocations at the next applicable billing date.

Consultation Question 15: Stakeholders are requested to comment on the principles for the wheeling arrangements and third-party access; in particular the embedded generator capacity of 300MW.


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c. Inter-distributor wheeling

The entry and exit DUOS charges take care of inter-distributor wheeling, as follows:

Where there is wheeling of energy to a customer through one distributor’s network to another, the end-customer will be required to pay the DUOS charges of the last distributor that supplies the capacity.

Each distributor that the energy is wheeled through will purchase capacity from the selling distributor (at the DUOS of the selling distributor) and will then sell on this capacity to the next distributor.

DUOS charges for inter-distributor wheeling will be the same exit charges as the DUOS exit charges for the load customers in the distribution area.

Consultation Question 16: Stakeholders are requested to comment on the principles for inter-distributor wheeling arrangements.

d. Bypass of Distribution network services

The pooling of costs to determine average cost-reflective rates inevitably leads to the real cost of service exceeding the rate for distant customers, whereas the rate will exceed the real cost for customers closer to the MTS. This may encourage some customers to bypass the distribution network, either by purchasing distribution assets or by constructing their own networks.

The cross-subsidisation from close to distant customers is an inevitable and a necessary part of cost pooling and average pricing. If bypassing is allowed, the price to the distant customers will simply increase, leading to a greater extent of bypass, until the price to the customers furthest from the transmission system becomes un-affordable.

At present there is not yet retail competition for electricity in South Africa. Since all customers are supplied by a regulated retailer and each retailer is dependent on a regulated network service, hence the uneconomic bypass of distribution network services is regulated by NERSA.

Consultation Question 17: Stakeholders are requested to comment on the principle of preventing uneconomic bypass of distribution services.


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4.4 Special Supply Conditions

a. Premium supplies

The cost of operations, maintenance and refurbishment of networks is included in the DUOS charges.

Premium supply customers will be required to pay all refurbishment costs associated with dedicated premium assets as a separate arrangement with the utility.

The refurbishment of shared premium assets and the maintenance and operating costs associated with the premium supply should be recovered through the regulated DUOS charges, owing to the complexity of calculating these charges accurately.

b. Contingency supplies

A customer that requires a contingency supply (as back-up in the event of a failure of customer-owned generation or load control equipment) will be provided with such a supply on the basis of firm notification of demand only. The charges applicable will be the DUOS charges for a credible notified maximum demand.

No (unfirm) contingency demand will be contracted for distribution capacity, as in practice this capacity is always made available and therefore should be charged accordingly.

c. DUOS charges for short term capacity requirements

Customers who have specific short-term (less than 12 months) network capacity needs are permitted to use the distributor’s existing available network capacity (i.e. no additional capacity will be created) and not pay full DUOS network charges. The more frequent the use of such capacity and the less short term it is used, the closer the full network charge rate should be to the DUOS network charge rates. Note that there is no waiver for embedded TUOS charges.

d. Diversity

The distributor may grant the benefit of diversity on the DUOS network demand charge to customers with more than one point of delivery on the same account, provided they comply with the rules and criteria determined by the distributor.

The following principles are used to guide the development of these criteria:


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o The customer should be able to transfer load between different points of delivery.

o The benefit applies to a single company.

o All points of delivery should be the same tariff.

o All multiple points of delivery should be fed off the same distributor ring or radial feeder.

o The points of delivery should be interconnected through a customer-owned interconnector so that the customer can internally transfer loads between these points.

The benefit of diversity will not apply to the DUOS network access charge. The concept of applying diversity to the network access charge, which recovers capital costs, is not cost-reflective. If two points of supply can swing load between each point, this is irrelevant when determining the fixed cost of the network, since upstream costs are allocated on the simultaneous demand on the networks and therefore already accounted for in the DUOS rates.

Diversity may be granted on the DUOS network demand charge as the cost associated with this charge is dependent on the amount of capacity used. It is not cost-reflective, but a concession to customers that have the benefit of diversity. In order to be totally cost reflective it should not be applicable.

Consultation Question 18: Stakeholders are requested to comment on the treatment of premium supplies, contingency supplies, short term supplies and the treatment of diversity.

4.5 Contractual Arrangements

a. Contractual Obligations

The distributor will enter into a contract with the customer for the use of the distribution network for all DUOS charges, including transmission services.

The quality of supply should be contracted in accordance with NERSA’s power quality directive, the Distribution Grid Code and NRS 047.

Generators who want network access has to

apply for a network connection, even if embedded in a plant and the Generator does not intend to export onto the network;

pay the associated connection charges as agreed with the Distributor;


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sign a connection and use-of-system agreement with the owner of the network;

pay the associated tariff charges; and

obtain the required approval from NERSA to generate and trade.

b. Transaction Voltage

The transaction voltage is the lowest voltage at which the supplier’s networks interface either with exit or entry to the network (i.e. the lowest voltage of either the take-off point or injection point).

c. Metering and Billing

The following metering and billing rules are proposed:

Customers will contract and be billed for the approved DUOS charges by the distributor supplying the capacity at their connection point.

The energy delivered to the customer must be billed to the trader supplying the customer. Load-profile metering will be required at each point of delivery of the customer, as well as at each point where the energy is injected into the distributor’s network.

The cost of the metering at the customer’s point of delivery, as well as any special metering requirements at the injection point(s), shall be debited to the customer.

Where the customer can both import and export metering, bi-directional four-quadrant metering has to be provided.

All the parties to the transaction have to agree on the responsibility and procedures for meter reading and billing. The parties to such a transaction are as follows:

o The generator for the supply of energy o The Transmission Network Company for the provision of transmission

services, including reliability services o The distributor(s) for the provision of transportation services o The end customer

Consultation Question 19: Stakeholders are requested to comment on the contractual obligations and the proposed metering and billing rules.

The EPP requires that bills must be itemised in compliance with NRS047. 4.6 Rules for the reconciliation of accounts


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In terms of the third-party access framework, an Eskom Customer may purchase/receive a portion of its energy from a non-Eskom Generator and the remainder from Eskom. When adjusting the Eskom Customer’s account due to the flow (physical or through a trade) of energy between the non-Eskom Generator and the Eskom customer, the following principles are used:

The reconciliation of accounts will be done on a TOU basis. Half-hourly meter reading data will be obtained for the energy produced by the non-Eskom Generator at the point of generator connection. This data will be used to adjust the partial service customer’s bill as well as billing the non-Eskom Generator for use-of-system charges.

The non-Eskom Generator can nominate more than one purchaser.

The energy adjustment for the Eskom Customer will be based on the net energy sent out by the non-Eskom Generator. The impact on network losses associated with the Generator is ignored in any adjustments made to customers’ bills.

This adjustment will take the form of a financial credit at the Megaflex >132kV Transmission Zone 1 energy rate, irrespective of the Eskom Customer’s tariff. The Megaflex energy rate is used as this is a published tariff and aligned to the wholesale energy rate. The energy purchased from the non-Eskom Generator is not subtracted from the energy supplied by Eskom. This is to ensure the recovery of non-energy related costs that are recovered through energy (kWh) charges in various tariffs.

Eskom will supply the Eskom Customer any energy not provided by the Generator. This is currently at standard tariffs, but in future may be subject to power conservation programme penalties or be charged at a standby rate. Eskom will be investigating a standby rate and making a submission to NERSA in the near future on the structure and value of the rate.

The purchaser of energy will pay:

o The cost of providing reliability services for the energy supplied by the non-Eskom Generator.

o The Electrification and Rural Subsidy on all energy delivered to the Customer over Eskom’s networks, unless the purchaser is exempt by NERSA or government from paying these subsidies.

o Network charges on all energy delivered to the customer over Eskom’s networks based on the customer’s utilised capacity and maximum demands as this does not impact the capacity of the network.

o For losses on all energy delivered to the customer over Eskom’s networks. These losses will be charged for at the standard tariff loss factors. The energy adjustment for the load will be based on the net energy sent out by the non-Eskom Generator plus losses at the standard tariff loss factors (voltage and transmission).


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Purchasing of energy:

o The purchase price paid for energy is dealt with through a power purchase agreement between the seller and the purchaser.

o However, for technical and contractual reasons, Eskom will have to be informed of any bilateral agreement between the Consumer and the Generator.

o The Customer will need to enter into a supplemental agreement to the supply agreement with Eskom, to deal with the conditions of the settlement.

The environmental levy will be raised on all energy supplied. The environmental levy will be addressed in the specific power purchase agreement.

Consultation Question 20: Stakeholders are requested to comment on the rules for reconciliation of accounts.

4.7 Subsidies and Levies

a. Subsidies

The TUOS and DUOS charges are used as the vehicle to implement explicit subsidies to specific categories of customers as per the EPP.

Implicit subsidies due to customer segmentation decisions and the averaging of rates, where for historical and affordability reasons the tariff being subsidised is lower than cost is an ongoing feature of the pooling of customers and networks when tariffs are structured to recover the allowed revenue of distributors.

b. Rate rebalancing levy

It is proposed that a rate-rebalancing levy be imposed on all electricity customers (loads and generators), excluding international customers, to make a contribution to cross-subsidies. The following rules are proposed:

The levy will be charged at the Transmission exit points (the points at which the load is taken) by the distributor as an energy charge to customers connected to or transporting energy through urban distribution networks.

Levies will be adjusted from time to time, based on the most recent cost-of-supply studies and financial information of network service providers.


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Consultation Question 21: Stakeholders are requested to comment on the proposed approach to fund contributions to levies and distribute subsidies through a rate rebalancing levy.

c. Revenue neutrality surcharge

Retailers are required to offer regulated tariffs to their customers who are segmented into categories. Average rates are calculated for these customer categories. It is the intent of the Electricity Pricing Policy that tariffs should be cost reflective to customer categories rather than to individual customers. This implies that by using average rates, there are inherent implicit subsidies in the tariff rates. These inherent subsidies in the DUOS charges, based on the tariff design decisions and averaging of costs, apply to all customers connected to and making use of the distribution system i.e. tariffs will be deemed to be adequately cost-reflective if cost is allocated in accordance with an acceptable cost of supply methodology..

A customer being supplied on an unbundled tariff will see a revenue effect when converting from an existing bundled retail tariff. This conversion should not affect a distributor’s or the retailer’s revenue – negatively or positively – and should be managed by levying a surcharge.

This surcharge also ensures that customers directly connected to the transmission system that do not pay DUOS charges and thus avoid contributing to inherent subsidies (such as high-voltage to low-voltage subsidies), also make a contribution.

Consultation Question 22: Stakeholders are requested to comment on the proposed revenue neutrality surcharge


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CHAPTER 5 – PUBLIC CONSULTATION PROCESS

Stakeholders are asked to comment in writing on the proposed Regulatory Rules on Network Charges for Third-Party Transportation of Energy. Written comments can be forwarded to [email protected]; hand-delivered to 526 Vermeulen Street, Arcadia, Pretoria or posted to PO Box 40343, Arcadia, 0083, Pretoria, South Africa.

Stakeholders will have another opportunity to present their views on the consultation paper at a public hearing scheduled for 07 July 2011. The public hearing will take place at the NERSA Auditorium, Kulawula House, Pretoria. Members of the public and stakeholders wishing to attend the hearing or present their views must submit their request to the following email address: [email protected]

For more information and queries on the above, please contact Ms Lehuma Masike or Mr Jeffrey Zwimbane at the National Energy Regulator of South Africa, Kulawula House, 526 Vermeulen Street, Arcadia, Pretoria. Tel: 012 401 4600 Fax: 012 401 4700

The closing date for comments is 27 June 2011 at 16:00.



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