Download Position Paper: Transmission / Distribution Asset Demarcation

Transmission / Distribution Asset
Demarcation
Position Paper: Transmission / Distribution
Asset Demarcation
Document Information
Document Version Number
Document Type
Title
Applicability
Status
Author
Signed off by:
Mr Peter Craig
Version 5
Position Paper
Transmission / Distribution Asset Demarcation
EDI Holdings
Final
Eskom
Sign-off date
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Transmission / Distribution Asset
Demarcation
Table of Contents
1
2
2.1
2.2
2.3
2.4
2.5
2.6
2.7
3
3.1
3.2
3.3
3.4
4
4.1
4.2
5
6
7
8
9
10
11
12
13
Introduction.....................................................................................................................................4
Background ....................................................................................................................................4
The EDI Blueprint ...........................................................................................................................4
Transmission / Distribution System Definitions...............................................................................5
NER’s Proposal for Allocation of Network Assets...........................................................................6
NER’s Views regarding Application of the 132kV Rule ...................................................................8
Convergence and Concerns in applying the 132kV Demarcation...................................................8
Principles to Determine Decision regarding Substations with Tx Voltages .....................................9
Eskom Implementation Developments ...........................................................................................9
Demarcation of assets in substations with voltages above and below 132kV ..............................10
Equipment in existing Eskom Tx s/s’s operating at nominal voltage of 132 kV or lower ...............10
Recommendation for the splitting of existing Substations with voltages above 132kV .................11
Future and significantly modified Transmission Substations ........................................................12
Actual demarcation point. .............................................................................................................14
Networks, 132 kV or lower, connecting generators or contestable customers directly to Tx s/s’s 14
Connecting Transmission substations and Generating equipment:..............................................14
Connecting contestable customers:..............................................................................................15
International Inter-connectors .......................................................................................................15
> 132 kV lines and s/s equipment currently belonging to Metros..................................................17
Short lines operating at 132 kV or below, but directly interconnecting Tx s/s’s.............................18
Certain lines constructed with the capacity to operate at above 132 kV, but integrated initially with Dx
networks .......................................................................................................................................18
Emergency supply facilities to nuclear power stations..................................................................19
Traction lines ................................................................................................................................19
Land rights and servitudes............................................................................................................19
Way foreword ...............................................................................................................................19
Annexure A...................................................................................................................................20
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Key Abbreviations
EDI
ESI
Dx
Tx
Gx
RED
NTC
DME
NER
NERSA
SOE
DPE
kV
s/s
SLA
EHV
HV
MV
LV
SNO
KSACS
Electricity Distribution Industry
Electricity Supply Industry
Distribution
Transmission
Generation
Regional Electricity Distributor
National Transmission Company (future)
Department of Minerals and Energy
National Electricity Regulator (as previously referred to)
National Energy Regulator of South Africa
State Owned Enterprises
Department of Public Enterprises
kilo Volt
substation
service level agreement
Extra High Voltage (above 132kV)
High Voltage (above 22kV up to & including 132kV)
Medium Voltage (typically 11 & 22kV)
Low Voltage (below 1000 volts)
Second Network Operator – Neotel (Pty) Ltd
Key Sales and Customer Services department
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Executive Summary
This document aims to guide Eskom, Municipalities and future REDs on
determining the exact demarcation with respect to ownership, rights and
obligations. It also proposes an alternative design of future Transmission
substations to be more closely aligned to a 132kV voltage demarcation.
Section one, paragraph 2:
Back ground on the blueprint as well as the development and discussions within
Eskom Transmission and Distribution. It also indicates the views of NERSA.
It addresses concerns in applying the 132kV demarcation as well as guidelines
regarding the principles for substations with above 132 kV voltages.
Section two paragraph 3
This section deals with the demarcation of existing Transmission substations. It
deals with pros and cons of demarcation strictly according to voltage (132kV)
against a more operational demarcation (the outer fence of the existing
transmission substations).
This section also address the design of future substations, the aim to build more
voltage demarcated substation in the future.
Section three paragraphs 4 onwards.
This section deals with all the other issues where Transmission own and operate
lines of 132kV and lower voltages. It also addresses feeders crossing the
international boundaries and assets owned by the municipalities with above 132kV
voltages.
1
Introduction
Determining the exact demarcation with respect to ownership, rights and
obligations is one of the requirements for the smooth transfer of assets from
Municipalities and Eskom for RED establishment, whatever form they may take in
the future. The EDI Blueprint and NER documentation have provided a framework,
yet clearer direction especially with respect to asset ownership, rather than
definition, is still required.
This paper explores some of the questions and concerns regarding the
Transmission / Distribution Asset Demarcation. Several positions are
recommended which aim to guide Municipalities and Eskom and provide the main
principles from which specific assets are defined for transfer.
2
2.1
Background
The EDI Blueprint
In 2001, the ‘Reform of the Electricity Distribution Industry EDI in South Africa Strategy and Blueprint’ document was approved by Cabinet. Contained within it
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is the following extract regarding the boundary between transmission and
distribution networks:
“The boundary between transmission and distribution should, in our view, be
based as far as possible on a simple voltage definition. Attempts in other
countries to use functional distinction (i.e. to define assets to be either
transmission or distribution according to their function) have been fraught with
difficulties – not least because the function of pieces of the network can change
over time. We propose that distribution be defined as all electrical networks at
132kV and lower voltages, and associated equipment, with the following limited
exceptions:
132kV circuits that are international inter-connectors;
short lengths of 132kV circuits linking transmission facilities;
132kV bus-bars at transmission substations which provide dedicated
connections to generation;
dedicated generation connections; and
high voltage circuits which have a clear distribution function and in
particular those currently being used by the municipalities & Eskom.”
2.2
Transmission / Distribution System Definitions
In July 2002, the NER issued a document entitled ‘Definition of the
Transmission/Distribution Systems for the Provision and Regulation of Network
Access in the Restructured EDI and ESI’ compiled by the ESI Transmission
Group. The definition of the systems was intended to ‘provide the platform for
the regulation of network businesses, the provision of network access to market
participants and the design of wholesale electricity tariffs’. It included the
following:
The transmission system should be defined as all assets operated
exclusively at a nominal voltage above 132 kV.
The distribution system should be defined as all assets operated
exclusively at a nominal voltage of 132 kV or lower.
Transmission transformation equipment should be defined as equipment
linking the transmission system to the distribution system or linking the
transmission system to generation or end-use customers.
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Figure 1: DEFINITION OF THE TRANSMISSION/DISTRIBUTION SYSTEMS AND
TRANSMISSION CUSTOMERS
Transmission
system
>132 kV
Transformation
equipment
<=132 kV
Generation
customers
End-use
customers
Distribution
system
The above diagram is also extracted from this NER document. From the
document and debates in various technical forums, it can be assumed that:
Equipment of 132kV and below linking the distribution system to generation
or end-use customers equipment, forms part of the distribution system
definition,
Plant and buildings such as auxilliary equipment and control rooms, in
support of primary (power) plant falling in either of these three definitions,
falls into the primary plant’s definition,
Where equipment etc. supports a combination of primary (power) plant,
such as a battery bank, it forms part of the definition of the primary plant of
the higher voltage, and
Distribution defined equipment (in substations with above 132kV) includes
the busbars at 132kV and below and the jumpers to the transformer links.
2.3
NER’s Proposal for Allocation of Network Assets
In August 2004, the NER issued another, draft, document titled “Allocation of
Network Assets to Transmission and Distribution Entities” in the Restructured
EDI and ESI’, requesting a consolidated response from Eskom.
This document specifically states that the ‘REDs will be responsible for provision
of access to the distribution system within their area of supply’ and ‘will therefore
also be responsible for planning and development of all 132 kV networks,
including the assets at the transmission substations.’
Since the detail of the demarcation of assets between a RED and a future
National Transmission Company (NTC) is still in the process of being finalised
and the EDI Blueprint proposal (that also presents a number of exceptions from
the voltage-defined demarcation) is in contrast with the current asset allocation
internal to Eskom, this document from the NER (in its final form following
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commentary from the various stakeholders) was intended to inform government
of the decision to be made for the allocation of assets to either transmission or
distribution entities in the unbundled Electricity Supply Industry (ESI).
It goes on to say that asset ownership should not be detrimental to the provision
of non-discriminatory access and obligations of service providers should be welldefined. It does not state which of these cross-ownerships can be allowed and
on what basis. One of the conditions of cross-ownership would be to put an
obligation on the ringfencing of the relevant assets. This will be required to
ensure proper cost allocation for tariff calculations and the development of crosssubsidy mechanisms.
This draft NER document recognised that practical ‘factors such as current
ownership, cost considerations/efficiencies, operational considerations and
physical impediments would provide arguments to the contrary’ of assets being
allocated purely according to systems definitions. The following evaluation
criteria (as extracted directly from this document) should however be used in
objectively determining this:
Consistency:
Given a specific allocation has been made, it needs to be consistently
applied for similar situations.
Safety:
Allocations should not be made in a way that will significantly impact
negatively on personnel safety.
Financial implications:
Allocation decisions should not result in severe cost implications, unless
direct benefit can be identified to mitigate these expenses. It is acceptable
to incur costs to adjust contracts, transfer assets financially, change-over
control systems and similar level of activities. It is not acceptable to move
assets such as transformers or to construct new buildings.
Existing commercial arrangements:
Existing arrangements should be honoured in the new environment.
Operational authority:
Responsibility for operations should be clearly definable i.t.o. the new
allocation. The System Operator area of control does not have to mirror the
assets owned by the national Transmission Network Service Provider.
The draft document goes on to list exception proposals (most of which refer to
Eskom’s recommendation, still to be provided, for the detail) concerning the
following:
132 kV circuits that are international interconnections,
Substations containing assets operating at voltages above and below 132
kV,
Networks operating at 132 kV or lower, which connect generators or
contestable customers directly to transmission substations,
275 kV lines and 275 kV substation equipment currently belonging to
Metros,
Certain short lines operating at 132 kV or below, directly interconnecting
transmission substations,
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Certain lines constructed with the intent to operate at above 132 kV, but
integrated initially with Distribution networks,
Emergency supply facilities to nuclear power stations, and
Transmission Transformation Equipment.
Each of these require a consolidated and detailed position and case by case
demarcation from Eskom. Compensation is assumed for the transfer of the
assets from one entity to another in this draft NER document.
2.4
NER’s Views regarding Application of the 132kV Rule
In various discussions with the NER and in its above mentioned documentation,
the following is a summary of their position:
The NER’s preference is the demarcation of ownership using the
application of the 132kV rule without exceptions for regulatory simplicity.
System definitions (i.e. >132kV as transmission, =<132kV as distribution
and transmission transformation equipment in between) are intended to
provide a platform for
– regulation of the businesses,
– non-discriminatory network access to customers etc. and
– the design of electricity tariffs.
The NER wants Eskom, distribution and transmission together, to propose
a common consolidated stance and proposal with respect to the
Transmission / Distribution boundaries, demarcating owners and governors
of control with respect to network plant.
Although the NER has the preference that ownership boundaries follow
system definition boundaries, it will not be prescriptive in this respect.
If ownership does not follow system definitions, ‘accounting’ will have to be
split appropriately to still provide for distinct regulation of transmission and
distribution systems and costs as per 132kV definition.
A recent letter from the NER has formally indicated their favouring ownership by
Distribution of 132kV and below equipment in substations.
2.5
Convergence and Concerns in applying the 132kV Demarcation
With the developments in the EDI and following engagement with various
parties, the following conclusions were reached:
The EDI Blueprint, NER and EDI Holdings (Operations/Wires) prefer an
almost pure 132kV and below demarcation for Distribution asset ownership
including in substations. The main reason for this preference is regulatory
simplicity, especially for pricing.
Parties in Eskom Transmission, Distribution and KSACS have converging
views on all asset allocation issues to align as closely to the 132kV
demarcation (see Section 3 below), yet there are diverse considerations
concerning substations.
Initially, operational and technical arguments were considered to offset
each other and be equally valid for substation ownership splits versus the
substation fence denoting the ownership boundary.
– The main argument in support of the substation fence demarcation is
related to ensuring safety and security through limited substation
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access (e.g. for manual control, maintenance, equipment
replacements etc.).
– The main arguments in support of the substation ownership split
(other than those given above) are related to limiting duplications and
inefficiencies in skills, stock, spares etc. and the fact that ownership
provides Distribution with the required leverage to deliver in areas
where the NER holds it accountable and responsible.
However, practical realities identified by Eskom (see 2.7 below), during the
‘tagging’ of assets in substations for transfer, have highlighted more
significant risks with respect to safety.
2.6
Principles to Determine Decision regarding Substations with Tx Voltages
The following principles underlie a final decision around substation asset
ownership:
Simplicity of implementation
Voltage cost ‘buckets’ clear
NER’s ‘acceptance of principles’
EDI Holdings acceptance
Operating stability
Technical integrity
Less relationship dependent
Transmission’s financial sustainability
Comprehensive service level agreements are required to define
relationships concerning refurbishment, reinforcement, network operating,
supply quality etc. with penalties and incentives included to provide
leverage and control to parties where necessary.
2.7
Eskom Implementation Developments
In 2005, Eskom Transmission and Distribution, subject to the underlying
principles being achieved, commenced with the preliminary work to have
financial asset ownership follow the 132 kV demarcation, yet have technical
custodianship (including operating and maintenance) remain ‘as-is’ in
Transmission Substations (i.e. with above 132kV plant).
As implementation of the above proceeded, especially in developing the contract
detail and understanding the financial and regulatory impact on Transmission,
the complexity and implications were determined and the decision partially
reviewed. During the course of defining the practical details per substation, it has
been concluded that operational risks (safety and control issues) with respect to
staff and plant integrity would be significantly increased, during and after the
transition in the splitting of ownership for most substations.
In the following section the pros and cons are listed for the two options.
Demarcation according to voltage
For existing substations demarcation at the outer fence of the Tx
substations.
Preferred position for future substations.
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3
Demarcation of assets in substations with voltages above and below
132kV
The most sustainable position should be created for the proper regulation of the
industry, even though this may require additional effort prior to RED or NTC
formation. Deviation from the Blueprint should only be applied if there are sound
arguments to indicate that this would be better for the long-term operations and
regulation of the industry.
Consistency in the principles agreed to and their application is a further
requirement in demarcating assets.
Ownership and completion of existing assets under constructions are to be
negotiated, but should follow the agreed principles.
Notwithstanding the end state of asset allocations, sound agreements should be
established between NTC/Tx and each RED/Dx entity, clearly defining
responsibilities towards each network asset whether owned by the parties or not.
The obvious elements would include maintenance, operations and reinforcement
rights and obligations, incentives and penalties. Rights and obligations around the
sharing of load information are less obvious, yet are examples of an essential
component for defining this contractual relationship.
3.1
Equipment in existing Eskom Tx s/s’s operating at nominal voltage of 132 kV
or lower
The table below provides a summary of some of the strengths and weaknesses
of either option i.e. demarcating substation ownership by its fence or by voltage
definition.
substation fence demarcation
substation ownership split
Advantages
Ownership rights with one entity to
enforce limited substation access to
ensure safety and security
Limits change by remaining ‘as-is’
– Less disruption to current industry &
lower restructuring cost
– Existing demarcation well
understood & documented by both
parties. Systems all in place &
stable. Staff stability – familiar with
responsibilities
Regulatory (incl. for utility
network performance) and
Pricing simplicity
Limits duplication and
inefficiencies in skills, stock,
spares etc. related to
technology and specifications of
equipment of a particular
voltage.
Ownership rights to (132kV and
below) plant provides Dx with
required leverage to deliver in
areas where the NER holds it
accountable and responsible.
Disadvantage
s
Dx dependency on contract to
enforce rights concerning
refurbishment, reinforcement,
network operating, supply quality
etc. for 132kV and below plant in Tx
substations
Some inefficiencies and duplication
regarding skills, stock, spares etc.
Greater regulatory and pricing
complexity
Dependency on contractual
rights to enforce limited and
controlled substation access to
ensure safety and security
A required change from the
existing state
– Significant change to
Transmission assets and cost
structures
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3.1.1 Issues concerning Separating Operations from Ownership
Network maintenance and operating can be separated from asset ownership to
address concerns around safety and other operational issues. However, a
comprehensive ‘contract’ between NTC/Tx and RED/Dx, will be required to
resolve the various concerns of either party. Splitting ownership of existing
substations according to voltage would be complex.
3.1.2 Practical Demarcation of Ownership
As mentioned above, from defining the practical details per substation, it has
been concluded that operational risks with respect to staff and plant integrity
would be significantly increased, during and after the transition in the splitting of
ownership for most substations as they are arranged and configured at present.
3.2
Recommendation for the splitting of existing Substations with voltages
above 132kV
As an alternative to a blanket application of the ideal regulatory demarcation of
equipment in substations, the following is recommended for practical
implementation:
3.2.1 Substations, that have no equipment with voltages above 132kV, are to
remain with or be transferred to RED/Dx.
3.2.2 As ‘a rule’, all assets currently within the fence of existing Transmission
substations, which have equipment with voltages above 132kV, remain in
the ownership of Transmission or are transferred to NTC/Tx, with the
following exceptions:
Assets that can be easily separated and ring fenced (with no complicated
integration issues or related costs to separate ) can be transferred to
RED/Dx, and
Assets that can, over a period of time and at low cost, be ringfenced and
transferred to RED/Dx.
3.2.3 Substations that need to be refurbished, replaced, upgraded or extended
must be investigated for voltage demarcation as part of the planned
project .
3.2.4 Responsibilities by NTC/Tx
3.2.4.1 NTC/Tx will be responsible for maintenance planning and
execution as well as initiating refurbishment of the 132kV and
lower voltage’s primary and affiliated equipment in the substations
owned by it.
3.2.4.2 Reinforcement and extension of the 132kV and lower voltage
equipment in substations owned by NTC/Tx will be the
responsibility of NTC/Tx on the initiative and request of RED/Dx.
Reinforcements and/or extensions done to NTC/Tx specifications,
yet in consultation with RED/Dx and charged within RED/Dx
costing constraints and/or requirements (i.e. more robust
specifications required by NTC/Tx, on 132kV and below
equipment in Transmission substations) are to be paid for by
NTC/Tx.
3.2.5 Future Transmission substations
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All future Transmission substations will be designed with 132kV and lower
voltage equipment in an independent and separated Distribution area in
accordance to the ideal 132kV demarcation. Exceptions due to technical and
financial viabilities are to be agreed to by both parties i.e. NTC/Tx and RED/Dx.
3.2.6
Classification of existing substations with voltages both above and below
132kV.
To give effect to the above, existing substations with equipment above
132kV should be classified and addressed as follows:
Type 1
Type 2
Type 3
Complex and highly
integrated substations where
the controls, protection and
access are integrated and
there are no plans for
upgrades and major
refurbishment.
Substations, or portions
thereof, where the layout and
integration of the controls,
protection and access are
currently separated.
Substations where
upgrading and major
refurbishment is required
and planned and appropriate
separation of Dx and Tx
equipment is viable.
For these substations, as long
as no plans exist for upgrades
or major refurbishment,
ownership of assets within the
substation outer fence is not
to be split and the whole
substation must remain with
or be transferred to NTC/Tx.
For these substations, or
portions thereof, the 132 kV
and lower equipment must
remain with or be transferred
to Eskom Dx as soon as is
practically possible on or
before transfer of assets into
RED.
For these substations, the
portion that can be
appropriately separated from
the Tx equipment (such as a
Dx project paid for from its
budget), should be
transferred to Dx once the
substation is recommissioned.
Key Advantages:
• Transfer is phased over a period of time as refurbishment or reinforcement is required
with gradual adherence to the 132kV voltage demarcation rule with respect to ownership.
• Safety and OHSAct requirements will not be jeopardised as a result of a less significant
and gradual transition.
• Complex access control, operations and maintenance SLA’s will not be necessary.
Key Disadvantages
• All equipment of primary voltage of 132kV and lower must still be ‘tagged’, ring-fenced or
apportioned in NTC/Tx asset register for regulatory compliance and reporting.
• A governance arrangement, process, penalties and/or incentives have to be created (e.g.
via NERSA or the SLA) to provide RED/Dx with leverage concerning refurbishment
and/or reinforcement options at substations and their timeous delivery.
3.3
Future and significantly modified Transmission Substations
The circumstances for each substation project e.g. servitude constraints,
availability of land, different utilities being supplied from the same substation,
existing substation layout and configuration, will largely determine the most
technically and economically viable design options in each case. However, in the
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creation of new Tx substations and the modification of others, consideration
should be given to the regulatory ideal substation 132kV demarcation as
provided above. The following are among the alternatives to allow for a closer
alignment to the regulatory ideal:
Option 1:
Option 2:
Direct supplies into a Dx Substation
Short busbar at Dx voltage
NTC/Tx provides supply at highest Dx voltage
requested and no secondary transformation
will form part of the Tx s/s.
A Distribution substation is created totally
independent from the Tx substation.
A short and additional secondary busbar is
created in Tx s/s to provide supply points for
different utilities and a location/junction for Tx
voltage supporting devices.
Tx substation’s boundary fence demarcates
asset ownership.
TX
TX
400/ 275 kV
400/ 275 kV
Possible
supply to
other utilities
DX
132/ 88/ 66kV
DX
132 /88/ 66kV
Note: Not all equipment is shown in above diagrams
Common Advantages
No overlap of OHSAct accountabilities and safety not jeopardized.
No shared equipment or services between Tx and Dx.
Distribution owned assets on Distribution owned land.
Secure access control.
Advantages
Advantages
No maintenance or operational SLA required for
the Dx yard.
Dx fully responsible for any upgrading or
refurbishment of equipment =<132kV.
NER can ring-fence according the 132kV Voltage
rule with minimal value of Dx defined assets
owned by Tx.
Voltage regulation equipment connected to busbars
owned and controlled by NTC/Tx.
NTC/Tx has control over design specification of
equipment installed for its supply points.
Less complex buszone inter tripping arrangements
required.
All equipment visible to Tx National Control and
telecommunication equipment self-contained
Disadvantage
Disadvantages
Tx voltage regulating equipment will be connected
to a busbar in a RED/Dx s/s.
NTC/Tx does not have direct control over design
standards for equipment on Dx busbars.
Tx will own equipment rated at =< 132kV in these Tx
substations with regulatory, skills, spares etc. issues.
Tx dependant on REDs/Dx when extensions are
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required e.g. additional transformer bays.
3.4
Actual demarcation point.
The actual demarcation point for existing substations where Tx will own 132kV or
lower voltage equipment.
Dx up to and including the terminal tower of any HV or MV line supplied from a
Tx substation. Special agreements is possible if the line is terminating in the Tx
yard.
4
Networks, 132 kV or lower, connecting generators or contestable
customers directly to Tx s/s’s
If the demarcation between Tx an Dx is defined as the outer fence of the existing
Transmission substations as mentioned above, consistency will require that it
applies for networks, operating at 132 kV or lower, which connect generators or
contestable customers directly to transmission substations.
The word ‘directly’ in the Blueprint exception limits its application to generators or
end-customers being connected directly to a 132kV (or below) busbar (dedicated
to a generation or customer feed) in a substation with equipment at voltage
levels above 132kV. Therefore, the exception should be applied as follows:
4.1 Connecting Transmission substations and Generating equipment:
For 132kV and below dedicated networks (no existing distribution
customers are connected to this line) connecting a Transmission substation
and generating equipment, the line is to be transferred to or remain with
Tx/NTC.
For future applications for access to 132kV and below dedicated lines
connecting Transmission substations and generation equipment, each
application must be investigated individually. The most appropriated
allocation of the demarcation between Tx and Dx must be negotiated
according to the unique circumstances
If Dx end-use customers are currently fed off 132kV and below networks
(connecting Transmission substation and generating equipment), then the
network by default is to be transferred to or remain with RED/Dx.
Although the most appropriated allocation of the demarcation between Tx
and Dx must be negotiated according to the unique circumstances
For 132kV and below networks connecting generating equipment and a
distribution substation (embedded in Dx networks), such networks to be
transferred or remain with RED/Dx.
There is a requirement that reassurance and guarantees be given to, or
contracted with, the System Operator for reliable transfer of power (from
either RED/Dx or NTC/Tx) to support the network where Generation
support is critical to system security and integrity.
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4.2 Connecting contestable customers:
For 132kV and below short dedicated lines (normally paid for by the
customer), connecting the current contestable customer and a
Transmission substation, will remain with Tx (status quo).
For any future connections or changes to the existing lines the situation
must be renegotiated between the customer, Tx and the RED/Dx.
Annexure A lists the current customers that are connected directly from
Transmission substation.
Networks connecting contestable customers embedded in the distribution
network are to remain with, or to be transferred to, the RED / Dx
Gx or
IPP
Dx line
Short dedicated line
Tx line
Current Contestable
customer
Tx line
Gx or
IPP
Dx line
Dx
Substation
For existing Tx substations
Dx
5
International Inter-connectors
Although Transmission is not permitted to purchase energy for sale to third
parties, it may provide and charge for its Wires services whether or not
competing Retailers or Traders surface.
Therefore, transmitting energy across international boundaries does not pose a
problem in terms of its operating licence.
Connectors’ functions may change (such as an international feeder becoming an
‘inter-connector’ due to reinforcement or generation across the South African
border) or a large customer within the South African border may apply for a
supply that would most appropriately be supplied off an inter-connector at 132kV
or below.
In view of the above, the application of the Blueprint exception should be as
follows:
All networks above 132kV crossing international boundaries should remain
part of, or be transferred to, NTC/Tx,
Page 15 of 20
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Transmission / Distribution Asset
Demarcation
Where the source network feeding the international consumer belongs to
Dx, a 132kV or below inter-connector up to the international border is to
remain part of, or be transferred to, RED/Dx,
Where the source network feeding the international inter-connector
belongs to a Dx or municipal entity, a 132kV or below inter-connector up to
the international border is to remain part of, or be transferred to, RED/Dx.
For source substations with above 132kV plant that are supplying
international consumers,
– Radial lines of 132kV and below, currently belonging to Tx feeding
end-customers across international boundaries with no Dx/RED
customer connected to that line, are to remain part of Tx up to the
international boundary.
– For future applications for access to 132kV and below lines
connecting Transmission substations and international customers,
each application will have to be investigated at the time of the
application regarding asset ownership, operation and possible wires
charges.
– If there are South African end-use customers connected along a
132kV or below interconnector, the line is to remain with, or be
transferred to, RED/ Dx, and
– Other network connectors (of 132kV and below) to other countries’
utilities (especially where these utilities generate), or network
connectors through other countries for parallel circuits, are to remain
with, or be transferred to, NTC/Tx.
Page 16 of 20
Ver 5 Signed 6/2/08 Mr. P Craig
Transmission / Distribution Asset
Demarcation
EHV Network (220kV and above)
HV Network (132kV and below)
MV Network (usually 22 & 11 kV)
Directly fed end-Customers across SA borders
radial networks feeding endcustomers across international
boundaries
International Utility
SA Customer
Parallel Circuit
SA Customer
, Dx ownership
, Tx ownership
Tx
ownership
without exception
If source substation is Tx station, apply as above. If source is a Dx station, then in all cases the lines will be Dx assets
Otherwise, Dx asset
6
> 132 kV lines and s/s equipment currently belonging to Metros
There is a very specific exception provided for in the Blueprint to allow above
132kV equipment, presently owned by Metros, to transfer to RED/Dx rather than
NTC/Tx. This would especially have operating benefits for networks above
132kV isolated from the transmission network by Distribution networks.
The current ownership structure arose historically. Practical considerations
meant that continued supply at 132kV or 88kV in the Metro area of supply
boundary was no longer a feasible option. The load had grown to a level that it
needed to be supplied at a transmission voltage i.e. greater than 132 kV. The
promulgation of the Transmission voltage tariff in 1985 also created a financial
incentive.
The most important benefit for Tx to own, operate and maintain networks of
above 132kV is to be able to have access and control of any possible ring or
parallel feeds on such networks, directly connected to existing Tx networks.
RED’s acquiring or owning networks of above 132kV still introduces tariff and
regulatory complexities (e.g. RED having to cater for above 132kV standards,
skills, spares etc.).
Therefore:
Clearly for operating simplicity, Metro networks above 132kV isolated from
the Transmission network by Distribution networks should be transferred to
REDs.
In addition, Metro networks above 132kV adjoining Eskom Transmission
networks of above 132kV should also be transferred to REDs, unless a
sound business case is provided for the overall benefit to the industry that
offsets the abovementioned concerns.
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Transmission / Distribution Asset
Demarcation
REDs may approach Eskom Transmission regarding the transfer of specific
plant. These cases must be negotiated to ensure the protection of each
party’s interests. If above 132 kV assets are transferred from the Metro to
NTC/Tx, the tariff will have to be restructured.
7
Short lines operating at 132 kV or below, but directly interconnecting Tx
s/s’s
The Blueprint exception, related to short sections of 132kV lines between Tx
substations, exists due to complexities (e.g. where Transmission reinforcement
requires an upgrade to 275kV or above) being more likely to arise in such cases.
However, a purer application of the 132kV rule with related simplicity, especially
where the line is later utilised to feed a new customer, has its benefits.
Therefore, the following is proposed:
If any such lines, operating at 132kV or below, are to form part of NTC/Tx
network, the asset transfer should be negotiated when a customer
connection is most viable off the 132kV line,
Planned upgrades of such lines are to be taken into account on a case by
case basis in determining which of these assets are to be transferred and
which will remain with NTC/Tx,
If the substation fence demarcates ownership and no future customers are
anticipated to be supplied off a 132kV and below interconnecting line, it is
to remain with, or be transferred to, NTC/Tx,
8
Certain lines constructed with the capacity to operate at above 132 kV,
but integrated initially with Dx networks
Certain lines constructed with the intention of operating at above 132 kV,
but integrated initially with Distribution networks are to remain with or be
transferred to NTC/Tx with the use of a regulatory leasing methodology to
influence Dx charges rather than Tx charges.
A line built to transmission voltage standards (e.g. for additional insulation
for pollution strength benefits), should be transferred to or stay with
RED/Dx, if there is no intention of upgrading its operating voltage in the
future, especially if customers are connected to the line.
Actual Customer
Potential Customer
Tx
Dx
Tx
or
Dx
275kV and above construction for strength or insulation with no intended use at /
upgrade to Tx voltage
Tx
or
Tx
Tx
Planned upgrade to 275kV and above
Tx
Tx
275kV and above construction for strength or insulation with no intended use at / upgrade to Tx voltage
Page 18 of 20
Ver 5 Signed 6/2/08 Mr. P Craig
Transmission / Distribution Asset
Demarcation
9
Emergency supply facilities to nuclear power stations
Applying the exception in the blueprint, emergency supply facilities to nuclear
power stations are to remain with, or be transferred to, NTC/Tx with the
Duynefontein-Vissershoek double circuit 132kV line remaining with RED/Dx.
10 Traction lines
Since the secondary circuit of Traction lines are mainly owned and serviced by
the customer, 220kV and above lines feeding Traction customers are to remain
with NTC/Tx. Lines of 132kV and below are to remain with RED/Dx.
11 Land rights and servitudes
A separate position paper will define the demarcation of property associated with
power lines and substations. Yet in summary:
Substation land, unless very clearly and geographically demarcated, should
generally not be subdivided for reasons of practicality and cost. The land of
an integrated Tx/Dx substation should be owned by NTC/Tx.
Other Dx facilities (e.g. training establishments or office blocks) existing on
such sites should be subdivided and transferred to RED/Dx where legally
possible and economically feasible. The option of a leasehold contract can
also be considered.
Joint Tx/Dx servitudes will remain with NTC/Tx subject to service level
agreements.
SLAs must be in place to specify these principles and to detail issues such
as the payment of rates and taxes. The cost of rates and taxes are to be
apportioned as per the 132kV demarcation.
12 Way foreword
Substation demarcation principles as discussed in this paper should be
implemented immediately.
Some more work is needed to identify all 132kV and below lines owned by
Transmission and to categorise them according this document.
Page 19 of 20
Ver 5 Signed 6/2/08 Mr. P Craig
Transmission / Distribution Asset
Demarcation
13 Annexure A
Customers Supplied Directly From Transmission Substations
(Below 220kV)
Tx Substation
Customer
Substation
Customer
Voltage
Level
Central
Olympus
Iscor
Mittal Steel
11kV
East
Athene
Invubu
Hillside
Rabbit
Exxano
RBM
132kV
132kV
North West
Ferrum
Iscor
Kumba Resources
66kV
North East
Sol
Sasol
Sasol
132kV
West
Gromis
Droerivier
Nama
Oranjemunt
Kleynsee
SAR
Okiep
CDM
Alexcor
Transnet
66kV
132kV
66kV
66kV
South
Page 20 of 20
Ver 5 Signed 6/2/08 Mr. P Craig
Notes
On
property
same