North Island 400 kV Upgrade Project
Investment Proposal
Part III – Analysis of Options for Meeting the
Investment Need
© TRANSPOWER NEW ZEALAND LIMITED 2005. ALL RIGHTS RESERVED
1
SUMMARY ....................................................................................................................................... 3
2
ASSESSMENT CRITERIA ............................................................................................................... 3
3
SUSTAINABILITY ............................................................................................................................ 4
3.1
Integration of Transmission and Diverse Generation............................................... 4
3.2
Reliability and Resilience of Transmission............................................................... 5
3.3
Transmission Losses................................................................................................ 5
3.4
Site Specific Mitigation ............................................................................................. 5
3.5
Overall Electricity Cost to the Consumer ................................................................. 6
4
TRANSMISSION OPTIONS ............................................................................................................. 6
4.1
HVAC Power Transmission Options ........................................................................ 6
4.2
HVDC Power Transmission Options ........................................................................ 7
4.3
220 kV HVAC Development Plan............................................................................. 7
4.4
Assessment of 220 kV HVAC Grid Upgrade Plan ................................................. 22
4.5
400 kV HVAC Development................................................................................... 23
4.6
Assessment of 400 kV HVAC Grid Upgrade Plan ................................................. 36
4.7
330 kV HVAC Development................................................................................... 36
4.8
500 kV HVAC Development................................................................................... 38
4.9
HVDC Link between South Island and Auckland................................................... 40
4.10
HVDC Link between Whakamaru and Otahuhu - Classical Configuration ............ 42
4.11
HVDC Link between Whakamaru and Otahuhu – HVDC Light Configuration....... 45
4.12
Underground Transmission Options ...................................................................... 48
4.13
Summary of Transmission Options ........................................................................ 50
5.1
Electricity substitutes.............................................................................................. 51
5.2
Generation Alternatives.......................................................................................... 51
5.3
Energy Efficiency Alternatives................................................................................ 55
5.4
Demand Side Management Alternatives................................................................ 55
5.5
Request for Information document......................................................................... 55
5.6
Alternatives to Transmission Summary.................................................................. 58
Part III – Analysis of Options for Meeting the Investment Need
2
1 Summary
Part III contains an analysis of all transmission options and alternatives to
transmission (including generation and demand side management) to meet the
demand identified as being required in the upper North Island from 2010.
The transmission options and alternatives for transmission which are determined by
Transpower as being credible options are then assessed against the proposed
investment from an economic perspective (such analysis being contained within Part
IV).
Transmission Options
Transpower’s high level assessment of transmission options against technical,
economic and environmental criteria showed that only 220 kV and 400 kV AC
overhead transmission options are credible options to meet the need identified in
Part II.
The following transmission options have been considered and assessed by
Transpower in this Part III:
• 220 kV development
• 330 kV development
• 400 kV development
• 500 kV development
• Classic HVDC development
• HVDC
Light
development
• Undergrounding
Alternatives to Transmission
Transpower issued a Request For Information to determine the potential alternatives
to transmission. Transpower assessed all alternatives offered through this RFI
process and concluded that peaking plant is the sole alternative to transmission
which would avoid or defer the need for the proposed investment and/or have a
reasonable likelihood of proceeding.
2 Assessment
Criteria
The criteria that Transpower has considered in assessing all transmission and non
transmission options are:
•
System Security – Whether the power supply to the upper North Island
meets an N-1 security standard in accordance with Transpower’s security
standard given the assumed demand and generation forecasts as set out in
this submission.
Part III – Analysis of Options for Meeting the Investment Need
3
•
Asset Availability – The availability of the various power system
components forming an essential part of the proposed development.
•
Economic Benefit – The net present value of the benefits that accrue from
the transmission option less all estimated capital and operating costs.
•
Environmental Feasibility – The feasibility of development options given
environmental constraints. The details of this assessment criteria are in
Appendix III-A.
•
Timing – The ability of the proposed development to be delivered by 2010.
•
Flexibility – The ability of the proposed development to be harmoniously
used together with the existing grid assets and future grid upgrades for
meeting the future demand growth and generation developments.
3 Sustainability
Transpower is committed to incorporating sustainability into its business activities
and to working with key stakeholders to promote sustainable outcomes for the
electricity sector.
In line with the government policy direction on sustainability1, the extent to which
transmission options contribute to sustainability can be assessed using the following
criteria:
1. Integration of generation from diverse sources at appropriate locations.
2. Improvement in network reliability/resilience
3. Reduction of transmission losses
4. Mitigation of site specific environmental impacts
5. Reduction of overall cost of electricity to the consumer
These criteria are considered in the following sections.
3.1 Integration of Transmission and Diverse Generation
The advantage of all transmission options compared to non-transmission alternatives
is through enabling integration of diverse generation sources (at appropriate
locations). This can lead to the following benefits
• Reduction in emissions of local air pollutants and reduction in greenhouse-
gas emissions where transmission provides connections to cleaner and/or
renewable forms of generation;
• Reduction in human exposure to ambient pollution, where transmission allows
separation of generation sources and points of electricity use (demand
centres);
• Potential reduction in long-range pollutant transport and regional problems
like acid rain where energy needs to be transported using forms other than
electricity transmission;
Nationally, New Zealand is required to reduce greenhouse-gas emissions under the
Kyoto Protocol. Without a reduced reliance on greenhouse gas emitting generation
1 October 2004, the government released a discussion document, ‘Sustainable Energy-Creating a
Sustainable Energy System’
Part III – Analysis of Options for Meeting the Investment Need
4
(and increased accessibility to hydro, solar, wind and/or other forms of energy), it is
apparent that the present trajectory of greenhouse-gas emissions will make
achievement of Kyoto targets a real challenge. A stronger grid will enable the efficient
use of renewable forms of energy such as wind power and hydro power whilst
maintaining a reliable supply of electricity to consumers.
3.2 Reliability and Resilience of Transmission
The reliability and resilience of the transmission network is also relevant from a
sustainability perspective and transmission upgrade options are evaluated taking
these into consideration.
Reliability of the transmission network refers to the ability of the network to make the
supply insensitive to a failure of a transmission component or a generating unit.
Resilience of the transmission network refers to the ability of the network to sustain
its value and functionality over a longer time and to accommodate the new
generation developments and meet long term demand growth.
3.3 Transmission Losses
Minimising transmission losses is an important consideration in meeting long term
sustainability. Transmission options are identified and selected taking the cost of
transmission losses into account. For example, options associated with an increase
in operating voltage provide greater environmental benefits through reduced
transmission losses over comparable line lengths. In general, transmission options
which reduce transmission losses are preferred because they:
• Reduce additional power generation needed to overcome power losses in
long-distance transfers;
• Reduce combustion emissions at the points of electricity generation;
• Reduce methane emissions from natural gas extraction, processing, and
distribution, if gas plants are the source of the electricity;
• Reduce possible human health and ecosystem effects from additional
generation plants and transmission lines; and
• Reduce environmental effects associated with generation from specific forms
of energy (nuclear, hydro, wind etc.).
The economic benefits of reducing transmission losses under each option are
considered in Section 4.
3.4 Site Specific Mitigation
Site specific environmental impacts of transmission options have been considered in
some detail under each option in Section 4 and will be further elaborated through the
RMA process. Environmental impacts are considered and assessed against the
other possible alternatives along each step of the transmission development process,
including area, corridor and route selection, transmission tower design and conductor
selection, employment of construction techniques and long term maintenance of the
assets and location, planning and construction of the terminating stations. The
transmission options are identified and selected with the objective of minimising any
Part III – Analysis of Options for Meeting the Investment Need
5
site specific adverse impacts and considering the ability for providing most effective
and economically efficient mitigation measures. Appendix III-A summarises the
process being followed.
3.5 Overall Electricity Cost to the Consumer
Transmission options are evaluated economically, using the Grid Investment Test,
which is a national cost-benefit analysis. To pass the Grid Investment Test a
proposal must maximise the net economic benefits to the market as a whole. Hence,
transmission options are evaluated in a manner which ensures the cost of producing
electricity is minimised.
Further, the transmission network is the platform upon which the electricity market
operates. By allowing consumers to access the cheapest form of generation
available any where in the country, competition is enhanced, ensuring the the cost of
electricity to consumers is minimised.
4 Transmission
Options
Transpower has assessed a range of transmission options that it considers are
capable of providing the necessary power transfer capacity to the upper North Island.
In summary this assessment includes:
•
High voltage alternating current (HVAC) options at 220 kV, 330 kV, 400
kV and 500 kV.
•
High voltage direct current (HVDC) transmission options at 350 kV, 500
kV and HVDC light.
•
The use of overhead transmission lines and or underground cables for
HVAC and HVDC applications.
The commitment to a new voltage level for the core grid is a strategic decision
involving the entire national grid and a decision on the appropriate voltage for grid
reinforcement between Whakamaru and Auckland needs to be considered in that
light.
4.1 HVAC Power Transmission Options
There are two broad development paths for HVAC transmission, namely:
•
Continuing with future grid development using 220 kV assets – in other
words maintaining the maximum voltage for New Zealand’s core grid at
220 kV.
•
Selecting a new maximum voltage (e.g. 330 kV, 400 kV or 500 kV) which
would be introduced as appropriate in the North and South Island
transmission systems.
All transmission proposals, including the use of higher voltages for the core grid,
would require the continued use of 220 kV for other parts of the grid where it is
economic to do so.
Part III – Analysis of Options for Meeting the Investment Need
6
In assessing the preferred future transmission voltage, Transpower has analysed
future possible grid developments under several generation scenarios and a medium
confidence load growth forecast. Of the HVAC options, the 220 kV and 400 kV
alternatives were ranked has the best two HVAC solutions and the results are
compared in detail in this section. A summary of the rationale for not following a
development path with maximum transmission voltage of 330 kV and 500 kV are also
included.
4.2 HVDC Power Transmission Options
Two generic HVDC transmission options to increase the power transfer levels into
Auckland were investigated. These options were:
• A bulk HVDC power transfer option connecting South Island generation and
transferring this directly to Auckland.
• The establishment of a short 200 km HVDC link between Whakamaru and
Otahuhu which is interconnected into the HVAC system at each end.
There are also two main choices of HVDC technology that are applicable to high
voltage power systems. HVDC power transmission requires the conversion of power
to HVDC using power electronic devices. Bulk electricity is then transferred at HVDC
through overhead lines or underground cables (or a combination). An inversion
process then converts HVDC power back to HVAC power at the receiving end. Two
means of converting the AC power to DC are presently available and are considered
as possible options:
Classical HVDC
• High voltage, high power, thyristor-based power conversion
technology.
• Power transmission could be by way of overhead line or
underground cable.
HVDC Light
• Relatively new, medium voltage (150 kV), transistor-based
power conversion technology.
• With the current technology, power transmission possible only
by underground cable
4.3 220 kV HVAC Development Plan
The following sections describe the future development of the grid under different
generation scenarios, if 220 kV is retained as the maximum transmission voltage.
As electricity demand increases, regional transmission connections and supply
transformers will become increasing overloaded and will require reinforcement. For
the purposes of this analysis, the focus is on the core transmission network and
therefore regional upgrades have been added to the power flow models as
necessary to remove overloading problems. While these solutions have not been
optimised, they are not considered material to the analysis of the core grid.
In this section a number of stages have been developed to group the necessary grid
upgrades into discrete steps. Stage 1 represents grid upgrades which are planned to
Part III – Analysis of Options for Meeting the Investment Need
7
take place approximately from 2010 to 2015, stage 2 are developments up from 2015
to 2020, and stage 3 are developments beyond 2020.
It should be noted that the high-level development plans in this section are based on
system planning studies. Detailed studies are required to confirm optimal location
and sizing of some reactive power investments and detailed engineering work is still
required to confirm feasibility and the appropriateness of the type of solution
employed. For example where an existing line is proposed for upgrading by installing
duplex conductors the existing towers may not be strong enough and they may
require replacement. Furthermore, where two single circuit lines are proposed for
duplexing, a single double circuit line may be built instead.
4.3.1 Grid Developments Before 2010
A number of tactical transmission upgrade projects are planned for implementation in
the North Island before 2010. A summary of these projects is given in the
Transpower publication: Future of the National grid – Transmission Plan Summary
2004. These projects are summarised in Appendix III-B.
Before 2010, the transfer capability into Auckland will be increased by a combination
of thermal upgrades of key transmission lines and increasing the level of reactive
power compensation in the region. After 2010, the power transfer into the Auckland
region will be mainly constrained by a voltage stability limit and the benefits of
installing more reactive compensation become limited as set out in Part II of this
submission. At this point Transpower considers that a major step change in
transmission investment is required.
4.3.2 220 kV Grid Development Plan for Generation Scenario 1 (Gas) from
2010-2040
The lines to be newly built or upgraded with duplex conductors under Generation
Scenario 1 (gas) at different stages are:
Stage
Transmission Line
Construct a 220 kV double circuit line Whakamaru to Auckland.
Upgrade 220 kV Tokaanu – Whakamaru A&B lines to duplex conductor.
Upgrade 220 kV Bunnythorpe – Haywards A&B lines to duplex
conductor.
1
Auckland cross Isthmus reinforcement with new 220 kV circuit (cable or
overhead).
Construct a 220 kV double circuit line Wairakei - Atiamuri - Whakamaru
in duplex zebra. String one circuit only.
Upgrade the 220 kV double circuit Stratford - Taumarunui – Te Kowhai -
Huntly line to duplex conductor.
New double circuit 220 kV –Taumarunui - Whakamaru line.
New double circuit 220 kV Stratford – Whakamaru line.
2
Upgrade the 220 kV Bunnythorpe – Tokaanu - Whakamaru lines to
duplex.
New double circuit 220 kV Bunnythorpe – Redclyffe line. String one
circuit only.
Part III – Analysis of Options for Meeting the Investment Need
8
String second circuit of 220 kV Wairakei – Atiamuri – Whakamaru line.2
Upgrade Atiamuri – Tarukenga A line with duplex conductor.
3
New single circuit 220 kV Hamilton - Huntly line.
Possibly dismantle 220 kV Otahuhu – Whakamaru A&B lines3.
New switching station near Huntly.
Table 4-1: 220 kV Grid Development Plan 2010-40 for Generation Scenario 1
In stage 1, the thermal upgrades and a new 220 kV double circuit line will be needed
to supply the Auckland load.
The existing HVDC link is also assumed to be upgraded to 1400 MW capacity by the
end of 2010. The associated core grid HVAC developments include upgrading the
existing 220 kV single conductor Hayward – Bunnythorpe A&B lines and Tokaanu -
Whakamaru A&B lines with duplex conductors (for increased HVDC transfer to the
South Island during low hydro periods, and increased northwards transmission
respectively).
In stage 2, upgraded and new lines will be required out of the Taranaki region to
Taumarunui, Huntly and Whakamaru to facilitate unconstrained dispatch of
generation in the Taranaki region to Auckland.
Additional new lines are also required to dispatch the generation from the
Bunnythorpe region and south (including HVDC import) to areas north of
Whakamaru.
Augmentation in stage 2 will need to be followed in stage 3 by reinforcement of the
220 kV grid for the transfers into Hamilton, into Bay of Plenty and through the
Wairakei ring.
The new switching station near Huntly is to connect the increased generation from
Huntly to the Otahuhu – Whakamaru lines.
The ultimate grid augmentation plan for a 220 kV transmission system for Scenario 1
is shown in Figure 4-1.
2 At this stage it may be possible to dismantle the existing lower capacity single circuit Wairakei –
Ohakuri – Atiamuri – Whakamaru line.
3 Towards the end of the planning horizon for this scenario there is a large increase in generation
capacity in the Auckland area, so the capacity of the Otahuhu – Whakamaru A&B lines may not be
required. As these lines will be old, they could be considered for dismantling.
Part III – Analysis of Options for Meeting the Investment Need
9
= Existing Lines
= New Lines
= Reconstructed or
Upgraded Lines
MDN
SVL
= Potential Lines for
BRB
Decommissioning
ALB
= HVDC
HEN
SWN
PEN
OTA
TAK
GLN
HLY-1
HLY-2
HAM
WPA
MOK
MTI
WKM
TRK
ATI
EDG
TMN
KAW
OKI
OHK
ARA
WRK
WHI
TKU
RDF
RPO
WTU
NPL
TNG
SFD
SPL
BRK
BPE
LIN
WIL
HAY
Figure 4-1: 220 kV grid configuration for Generation Scenario 1 at 2040
Part III – Analysis of Options for Meeting the Investment Need
10
4.3.3 220 kV Grid Development Plan for Generation Scenario 2 (Coal) from
2010-2040
The new lines to be built and those that are to be upgraded with duplex conductors
under Generation Scenario 2 (coal) are given below:
Stage
Transmission Line
Construct a 220 kV double circuit line Whakamaru to Auckland.
Upgrade 220 kV Tokaanu – Whakamaru A&B lines to duplex conductor.
Upgrade 220 kV Bunnythorpe – Haywards A&B lines to duplex conductor.
1
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or
overhead).
Construct a 220 kV double circuit line Wairakei - Atiamuri - Whakamaru in
duplex zebra. String one circuit only.
Upgrade double circuit 220 kV Bunnythorpe – Whakamaru line to duplex
2
conductor.
New double circuit 220 kV Bunnythorpe – Redclyffe line. String one circuit
only.
Upgrade Atiamuri – Tarukenga A line with duplex conductor.
String second circuit of the 220 kV Wairakei – Atiamuri – Whakamaru line4.
3
Upgrade the 220 kV double circuit Stratford - Taumarunui – Te Kowhai - Huntly
line to duplex conductor.
New double circuit 220 kV Taumarunui – Whakamaru line.
Table 4-2: 220 kV Grid Development Plan 2010-40 for Generation Scenario 2
In stage 1, the thermal upgrades and a new 220 kV double circuit line will be needed
to supply the Auckland load. The existing HVDC link is assumed to be upgraded to
1400 MW capacity by the end of 2010. The associated core grid AC developments
include upgrading the existing 220 kV single conductor Hayward – Bunnythorpe A&B
lines and Tokaanu - Whakamaru A&B lines with duplex conductors (for increased
HVDC transfer to the South Island during low hydro periods, and increased
northwards transmission respectively).
For stage 2, the upgraded and new lines from Bunnythorpe are for the new
generation in the Bunnythorpe and south regions to supply the load to the north.
For stage 3, the upgraded and new lines from Stratford to Taumarunui, Huntly and
Whakamaru are principally due to the new generation at Stratford and south of
Bunnythorpe, and for voltage stability to the Auckland area. The second Wairakei –
Atiamuri – Whakamaru circuit is for the new generation in the Wairakei area, and to
supply the Bay of Plenty load. The ultimate grid augmentation plan for a 220 kV
transmission system for Scenario 2 is shown in Figure 4-2.
4 At this stage it may be possible to dismantle the existing lower capacity single circuit Wairakei –
Ohakuri – Atiamuri – Whakamaru line.
Part III – Analysis of Options for Meeting the Investment Need
11
= Existing Lines
= New Lines
= Reconstructed or
MDN
Upgraded Lines
SVL
BRB
= Potential Lines for
Decommissioning
ALB
= HVDC
HEN
SWN
PEN
OTA
TAK
GLN
HLY
WPA
HAM
MOK
MTI
WKM
TRK
ATI
EDG
TMN
KAW
OKI
OHK
ARA
WRK
WHI
TKU
RDF
RPO
WTU
NPL
TNG
SFD
SPL
BRK
BPE
LIN
WIL
HAY
Figure 4-2: 220 kV grid configuration for Generation Scenario 2 at 2040
Part III – Analysis of Options for Meeting the Investment Need
12
4.3.4 220 kV Grid Development Plan for Generation Scenario 3 (Renewable)
from 2010-2040
The lines to be newly built or upgraded with duplex conductors under Generation
Scenario 3 (renewables) at different stages are:
Stage
Transmission Line
Construct a 220 kV double circuit line Whakamaru to Auckland.
Upgrade 220 kV Tokaanu – Whakamaru A&B lines to duplex conductor.
Upgrade 220 kV Bunnythorpe – Haywards A&B lines to duplex conductor.
1
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or
overhead).
Construct a 220 kV double circuit line Wairakei - Atiamuri - Whakamaru in
duplex zebra. String one circuit only.
Upgrade double circuit 220 kV Bunnythorpe – Tokaanu - Whakamaru line to
2
duplex conductor.
New double circuit 220 kV Bunnythorpe – Redclyffe line. String one circuit
only.
String second circuit of 220 kV Wairakei – Atiamuri – Whakamaru line5.
New double circuit 220 kV Whakamaru – Auckland line.
Upgrade the 220 kV double circuit Stratford - Taumarunui – Huntly line to
duplex conductor.
3
New double circuit 220 kV Taumarunui – Whakamaru line.
New single circuit 220 kV Hamilton – Huntly line.
New double circuit 220 kV Whakamaru – Otahuhu line6.
New double circuit 220 kV Whakamaru – Otahuhu line.
Table 4-3: 220 kV Grid Development Plan 2010-40 for Generation Scenario 3
In stage 1, the thermal upgrades and a new 220 kV double circuit line will be needed
to supply the Auckland load.
The existing HVDC link is assumed to be upgraded to 1400 MW capacity by the end
of 2010. The associated core grid AC developments include upgrading the existing
220 kV single conductor Hayward – Bunnythorpe A&B lines and Tokaanu -
Whakamaru A&B lines with duplex conductors. (for increased HVDC transfer to the
South Island during low hydro periods, and increased northwards transmission
respectively).
For stage 2, the upgraded and new lines from Bunnythorpe are for the new
generation in the Bunnythorpe and south regions to supply the load to the north.
5 At this stage it may be possible to dismantle the existing lower capacity single circuit Wairakei –
Ohakuri – Atiamuri – Whakamaru line.
6 It is assumed that the Otahuhu – Whakamaru A&B line routes would each be used for a new double
circuit line. Alternatively, these lines could be duplexed, in which case one less double circuit line is
required.
Part III – Analysis of Options for Meeting the Investment Need
13
In stage 3 upgrades for the transfers into Hamilton, into Bay of Plenty and through
the Wairakei ring, will be as per generation scenarios 1 and 2.
For this scenario very little new generation is projected in the region North of
Whakamaru. Therefore, significant reinforcements will be required in stage 3
between Whakamaru-Otahuhu, in addition to the double circuit line built in stage 1.
The ultimate grid augmentation plan for a 220 kV transmission system for Scenario 3
is shown in Figure 4-3.
Part III – Analysis of Options for Meeting the Investment Need
14
= Existing Lines
= New Lines
= Reconstructed or
MDN
Upgraded Lines
SVL
BRB
= Potential Lines for
Decommissioning
ALB
= HVDC
HEN
SWN
PEN
OTA
TAK
GLN
HLY
HAM
WPA
MOK
MTI
WKM
TRK
ATI
EDG
TMN
KAW
OKI
OHK
ARA
WRK
WHI
TKU
RDF
RPO
WTU
NPL
TNG
SFD
SPL
BRK
BPE
N
LI
L
WI
HAY
Figure 4-3: 220 kV grid configuration for Generation Scenario 3 at 2040
Part III – Analysis of Options for Meeting the Investment Need
15
4.3.5 220 kV Grid Development Plan for Generation Scenario 4 (Southern
Hydro) from 2010-2040
The new lines to be built and those that are to be upgraded with duplex conductors
under Generation Scenario 4 (hydro) are given below:
Stage
Transmission Line
Construct a 220 kV double circuit line Whakamaru to Auckland.
Upgrade 220 kV Tokaanu – Whakamaru A&B lines to duplex conductor.
Upgrade 220 kV Bunnythorpe – Haywards A&B lines to duplex conductor.
1
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead).
Construct a 220 kV double circuit line Wairakei - Atiamuri - Whakamaru in duplex
zebra. String one circuit only.
2
New HVDC link of capacity 600 MW from the South Island into Auckland7.
Upgrade Atiamuri – Tarukenga line to duplex conductor.
3
Construct a new 220 kV double circuit line Whakamaru to Auckland.
Upgrade the new HVDC link from 600 MW to 1200 MW.
String second circuit of 220 kV Wairakei – Atiamuri – Whakamaru line8.
Table 4-4: 220 kV Grid Development Plan from 2010-2040 for Generation Scenario 4
In stage 1, the thermal upgrades and a new 220 kV double circuit line will be needed
to supply the Auckland load.
The existing HVDC link is assumed to be upgraded to 1400 MW capacity during the
period 2010 - 2015. The associated core grid AC developments include upgrading
the existing 220 kV single conductor Hayward – Bunnythorpe A&B lines and Tokaanu
- Whakamaru A&B lines with duplex conductors. (for increased HVDC transfer to the
South Island during low hydro periods, and increased northwards transmission
respectively).
An increasing generation deficit develops in the North Island from 2010 onwards,
primarily caused by a large increase in load and a lack of new generation in the
Auckland and Northland region. With the upgrade of the existing HVDC, this deficit
can be supplied until 2020, at which point n-1 security under generation
contingencies can no longer be maintained.
For stage 2, a new HVDC link is assumed to be built from the South Island directly to
Auckland. It is built in two stages, and is required to import power from the South
Island directly to the major load centre in Auckland. Reinforcement of the 220 kV grid
into the Bay of Plenty by duplexing Atiamuri - Tarukenga will also be required.
7 The HVDC link is based on transmission capacity requirements only. The link must be such that it
provides 600 MW reliable supply capacity to the Auckland region. Security considerations may require
an arrangement, such as a double bipole.
8 At this stage it may be possible to dismantle the existing lower capacity single circuit Wairakei –
Ohakuri – Atiamuri – Whakamaru line.
Part III – Analysis of Options for Meeting the Investment Need
16
For stage 3, the new HVDC link to Auckland is upgraded to 1200 MW to provide for
additional load growth in the Auckland area. A new double circuit line is also required
from Whakamaru to Auckland for transferring power from the new generation
developments around Whakamaru and south of Whakamaru.
The ultimate grid augmentation plan for a 220 kV transmission system for Scenario 4
is shown in Figure 4-4.
Part III – Analysis of Options for Meeting the Investment Need
17
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
TAK
GLN
HLY
To South
Island
HAM
WPA
MOK
MTI
WKM
TRK
ATI
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
LIN
L
WI
HAY
Figure 4-4: 220 kV grid configuration for Generation Scenario 4 at 2040
Part III – Analysis of Options for Meeting the Investment Need
18
4.3.6 220 kV Grid Development Plan for Generation Scenario 5 (Reduced
Demand) from 2010-2040
The new lines to be built and those that are to be upgraded with duplex conductors
under Generation Scenario 5 (reduced demand) are given below:
Stage
Transmission Line
Construct a 220 kV double circuit line Whakamaru to Auckland.
Upgrade 220 kV Tokaanu – Whakamaru A&B lines to duplex conductor.
1
Upgrade 220 kV Bunnythorpe – Haywards A&B lines to duplex conductor.
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead).
New 220 kV double circuit Whakamaru-Atiamuri-Ohakuri-Wairakei line.
2
Connect second circuit on Otahuhu-Whakamaru C line into Huntly.
Upgrade Bunnythorpe-Tokaanu circuits to duplex conductor.
Upgrade Bunnythorpe-Tangiwai-Rangipo circuits to duplex conductor.
Connect Bunnythorpe-Tokaanu circuits into Rangipo.
Upgrade Rangipo-Wairakei circuits to duplex conductor.
3
Upgrade 220kV Otahuhu - Whakamaru A and B lines to duplex conductor.
Upgrade Atiamuri – Tarukenga A line to duplex conductor.
Connect second circuit of Otahuhu-Whakamaru C line into Hamilton.
New 220 kV double circuit Otahuhu - Whakamaru line.
Upgrade existing Wairakei-Whakamaru A line to duplex conductor.
Table 4-5: 220 kV Grid Development Plan 2010-2040 for Generation Scenario 5
In stage 1, the thermal upgrades and a new 220 kV double circuit line will be needed
to supply the Auckland load. A new double circuit line between Wairakei and
Whakamaru is also required for transferring the generation from south of
Bunnythorpe.
The existing HVDC link is assumed to be upgraded to 1400 MW capacity during the
period 2010. The associated core grid AC developments include upgrading the
existing 220 kV single conductor Hayward – Bunnythorpe A&B line and Tokaanu -
Whakamaru A&B line with duplex conductors. (for increased HVDC transfer to the
South Island during low hydro periods, and increased northwards transmission
respectively).
In stage 2, the Otahuhu-Whakamaru C line is connected into Huntly to increase the
transmission capacity due to increased generation at Huntly. The Huntly-Stratford
circuit is connected into Taumarunui to ease voltage problems during a contingency
with new generation at Stratford. The Bunnythorpe-Tokaanu circuits are connected
into Rangipo to improve sharing between the three circuits north of Bunnythorpe for
high HVDC transfer.
Other developments in this stage include duplexing the existing 220 kV Bunnythorpe-
Tokaanu A&B lines and the Bunnythorpe-Wairakei A line to meet the increasing
transfer requirement in the corresponding regions.
Part III – Analysis of Options for Meeting the Investment Need
19
In stage 3, the Otahuhu-Whakamaru A&B is upgraded to relieve grid constraints from
south of Otahuhu. The Otahuhu-Whakamaru C line is connected into Hamilton to
increase transmission capacity into the Waikato region and relieve constraints on the
existing Hamilton-Whakamaru circuit during low Huntly generation. A new 220 kV
circuit between Otahuhu-Whakamaru will be constructed to relieve the constraints
between Otahuhu and Whakamaru. Reinforcement of the 220 kV grid into Bay of
Plenty, and between Whakamaru and Wairakei, is also required.
The ultimate grid augmentation plan for a 220 kV transmission system for Scenario 5
is shown in Figure 4-5.
Part III – Analysis of Options for Meeting the Investment Need
20
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
TAK
GLN
HLY
HAM
WPA
MOK
MTI
WKM
TRK
ATI
EDG
KAW
OKI
OHK
ARA
TMN
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
LIN
L
WI
HAY
Figure 4-5: 220 kV grid configuration for Generation Scenario 5 at 2040
Part III – Analysis of Options for Meeting the Investment Need
21
4.4 Assessment of 220 kV HVAC Grid Upgrade Plan
4.4.1 System
Security
The proposed 220 kV HVAC grid development plan can be planned and
implemented to meet Transpower’s current grid reliability standards.
4.4.2 Asset
Availability
Table 4-6 shows the historical availability of the HVAC assets. The availability of the
new overhead 220 kV transmission assets is expected to be similar or better than the
existing 220 kV transmission assets, which is an acceptable level of performance.
Year
33/50/66
110kV 220kV Total
1999 / 00
99.7% 99.2%
2000 / 01
98.4%
98.6% 99.6% 98.9%
2001 / 02
99.2%
98.9% 99.4% 99.1%
2002 / 03
99.1%
98.6% 99.3% 98.9%
2003 / 04
99.2%
98.7% 99.4% 99.0%
Table 4-6: Historical Availability of HVAC Assets
4.4.3 Flexibility
All 220 kV transmission development plans allow flexibility for future expansion of the
grid, depending on the future generation developments and load growth.
4.4.4 Environmental Considerations
Power transfer capabilities of transmission systems increase as the system voltage
increases. Consequently, continuing with a 220 kV grid development strategy will
result in the greatest number of new transmission lines to be constructed between
major generation facilities and load centres across the country (when compared to
other higher voltage options).
While 220 kV transmission line tower heights are lower than the other high voltage
upgrade options, it is considered that the benefit of lower tower heights is
substantially outweighed by the need to establish more transmission line routes to
connect the major load centres to generation.
System losses are also highest for a 220 kV development plan when compared to
higher voltage choices. This brings forward the need for investment in generation
when compared to higher voltage (lower loss) alternatives.
In summary, when assessed over a 30-40 year period, a 220 kV development plan is
considered to cause the greatest overall environmental impact. This is based on this
development plan having the largest number of new transmission lines which cause
greatest disruption to land use and have a wider impact on communities over greater
areas the other higher voltage options.
Part III – Analysis of Options for Meeting the Investment Need
22
4.4.5 Economic
Analysis
The detailed economic analysis of this plan is contained in Part IV of this submission.
In summary the 220 kV development plan is has a national benefit assessed as $133
million lower than the 400 kV development plan.
4.4.6 Conclusion
A 220 kV HVAC development plan to cater for the needs of New Zealand’s demand
growth would provide satisfactory security of supply outcomes. However a 220 kV
development plan would require the highest number of new transmission lines to be
build especially between Whakamaru and Auckland, when assessed against all
generation scenarios. Given the difficulty in obtaining transmission corridors for
building new lines, and considering the adverse environmental impact, the ability to
implement such a plan in the long term is a concern. This option is also substantially
more expensive in national benefit terms than moving to a higher system voltage
choice such as 400 kV.
Transpower does not consider that a “no investment” outcome is a viable long term
choice for New Zealand as the amount of energy forecast to be unserved would have
massive consequences for the country as a whole. For this reason the 220 kV option
has been considered as the base case against which the economic benefits of the
other options are tested.
4.5 400 kV HVAC Development
The following sections describe the future development of the grid under different
generation scenarios, if the maximum transmission voltage for new core grid
transmission is increased to 400 kV. The 400 kV developments would be focussed
in the transmission corridors where significant power transfer is expected to take
place in the future. Development of the grid at 220 kV and 110 kV will also continue
in areas of the network with lower power transfer requirements.
In this section a number of stages have been developed to group the necessary grid
upgrades into discrete steps. Stage 1 represents grid upgrades which are planned to
take place approximately from 2010 to 2015, stage 2 are developments up from 2015
to 2020, and stage 3 are developments beyond 2020.
It should be noted that the high-level development plans in this section are based on
system planning studies. Detailed studies are required to confirm optimal location
and sizing of some reactive power investments and detailed engineering work is still
required to confirm feasibility and the appropriateness of the type of solution
employed. For example where an existing line is proposed for upgrading by installing
duplex conductors the existing towers may not be strong enough and they may
require replacement. Furthermore, where two single circuit lines are proposed for
duplexing, a single double circuit line may be built instead.
4.5.1 Development Plans before 2010
A summary of the grid upgrade projects which are expected to be implemented in the
North Island Power System before 2010 are given in the Transpower publication:
Future of the National grid – Transmission Plan Summary 2004. For conciseness, the
salient upgrade projects are summarised in Appendix III-B.
Part III – Analysis of Options for Meeting the Investment Need
23
Before 2010, the transfer capability into Auckland is increased by thermal upgrades
of lines and increasing the level of reactive power compensation in the region. After
2010, the power transfer into the Auckland region will be mainly constrained by a
voltage stability limit and no further significant transmission capacity can be provided
by thermal upgrades or reactive compensation. Further increase in transmission
capacity will require building new transmission lines especially between Auckland
and Whakamaru.
4.5.2 400 kV Grid Development Plan for Generation Scenario 1 (Gas) from
2010-2040
The new lines to be built and those existing lines to be upgraded with duplex
conductors under this generation scenario are shown below in Table 4-7:
Stage
Transmission Project
New 400kV double circuit Otahuhu – Whakamaru line
New 220 kV double circuit Wairakei – Atiamuri – Whakamaru line (string one side
only)
1
Duplex 220 kV Tokaanu – Whakamaru A&B lines
Duplex 220 kV Bunnythorpe – Haywards A&B lines
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead)
New 400 kV double circuit Bunnythorpe – Whakamaru line
2
New 400 kV double circuit Stratford – Whakamaru (new) line
New 220 kV Tokaanu-Taumarunui line9
Tap Rangipo 220 kV bus onto Bunnythorpe-Tokaanu 220 kV A&B lines
Duplex 220 kV Atiamuri – Tarukenga A line
String second side of 220 kV Wairakei – Atiamuri – Whakamaru double circuit line
3
Connect 400 kV double circuit line constructed in stage 1 into Huntly
Bond 220 kV Otahuhu – Whakamaru C line to create a single circuit
Table 4-7: 400 kV Grid Development Plan 2010-2040 for Generation Scenario 1
In stage 1
a new double circuit 400 kV line will be required between Otahuhu and
Whakamaru, to relieve grid constraints from south of Otahuhu. 400 kV substations
will be required at Otahuhu and Whakamaru to provide interconnection to the 220 kV
grid. Other developments in this stage include duplexing the existing 220 kV
Hayward – Bunnythorpe A&B lines and Tokaanu – Whakamaru A&B lines and
building a new double circuit line between Wairakei and Whakamaru to meet the
increasing transfer requirement in the corresponding regions. Reinforcement of the
grid across the Auckland Isthmus will be completed with a new 220 kV cable or
overhead line to increase the transfer capability to the North Isthmus and Northland
regions.
In stage 2
, the 400 kV network will be extended south to Bunnythorpe from
Whakamaru and west to Stratford to allow generation from Taranaki region and
9 This development assumes that the Stratford-Taumaranui-Huntly line and Tangiwai-Rangipo section of
the Bunnythorpe-Tokaanu A&B lines are decommissioned. However, the need fro decommissioning will
be assessed closer to the time depending on the condition of the asset and the generation
developments (especially wind generation) in the region.
Part III – Analysis of Options for Meeting the Investment Need
24
Bunnythorpe south (including HVDC import) to areas north of Whakamaru. This
development will allow the existing 220 kV Stratford – Taumarunui and Huntly –
Taumarunui line, the Tangiwai – Rangipo section of the Bunnythorpe – Tokaanu A&B
lines, and the entire Bunnythorpe – Wairakei line to be decommissioned.10 New 400
kV substations at Bunnythorpe, Stratford will also be built in this stage.
In stage 3
the 400 kV line built in stage 1 will need to be diverted to Huntly power
station by constructing a short section of 400 kV double circuit line for transporting
generation from Huntly. Reinforcement of the 220 kV grid into Bay of Plenty and
through the Wairakei ring will also be required.
The ultimate augmentation plan based on 400 kV option for Scenario 1 is shown in
Figure 4-6
10 The need for decommissioning will be assessed closer to the time depending on the condition of the
asset and the generation developments (especially Wind Generation) in the region.
Part III – Analysis of Options for Meeting the Investment Need
25
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
OTA
TAK
GLN
HLY
HLY
HAM
WPA
MOK
MTI
WKM
WKM
TRK
ATI
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SFD
SPL
BRK
BPE
BPE
N
400 KV Grid
LI
L
WI
HAY
220 KV Grid
Figure 4-6: 400 kV Grid Development Plan for Generation Scenario 1 at 2040
Part III – Analysis of Options for Meeting the Investment Need
26
4.5.3 400 kV Grid Development Plan for Generation Scenario 2 (Coal) from
2010-2040
The new lines that are to be built and those existing 220 kV lines that are to be
upgraded to duplex conductors for this generation scenario are shown below:
Stage
Transmission Project
New 400kV double circuit Otahuhu - Whakamaru line
New 220 kV double circuit Wairakei – Atiamuri – Whakamaru line (string one side
only)
1
Duplex 220 kV Tokaanu – Whakamaru A&B lines
Duplex 220 kV Bunnythorpe – Haywards A&B lines
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead)
New 400 kV double circuit Bunnythorpe – Whakamaru line
2
Tap Rangipo 220 kV bus onto Bunnythorpe-Tokaanu 220 kV A&B lines
Duplex Atiamuri – Tarukenga A line
String second side of 220 kV Wairakei – Atiamuri – Whakamaru double circuit line
3
Connect 400 kV double circuit line constructed in stage 1 into Huntly
Table 4-8: 400 kV Grid Development Plan 2010-2040 for Generation Scenario 2
The gird development plan in stage 1
is identical to the one developed for Generation
Scenario 1.
However, the new 220 kV circuits between Stratford –Whakamaru (new) required in
stage 2
for Scenario 1 are not required in this scenario. This is because the new
generation in the Taranaki region for Generation Scenario 2 is much less than that
for Generation Scenario 1 and therefore the capacity requirement between Stratford
and Whakamaru is significantly reduced.
The grid augmentation required in stage 3
is mainly for reinforcing the transfer into
the Bay of Plenty and through the Wairakei ring. Also the 400 kV line built in stage 1
will need to be diverted to Huntly power station by constructing a short section of 400
kV double circuit line for dispatching generation from Huntly.
The ultimate augmentation plan based on 400 kV option for Scenario 2 is shown in
Figure 4-7.
Part III – Analysis of Options for Meeting the Investment Need
27
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
OTA
TAK
GLN
HLY
HLY
HAM
WPA
MOK
MTI
WKM
WKM
TRK
ATI
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
BPE
N
400 KV Grid
LI
L
WI
HAY
220 KV Grid
Figure 4-7: 400 kV Grid Development Plan 2040 for Generation Scenario 2
Part III – Analysis of Options for Meeting the Investment Need
28
4.5.4 400 kV Grid Development Plan for Generation Scenario 3 (Renewables)
from 2010-2040
For Generation Scenario 3, the new lines to be constructed and the 220 kV lines that
are to be upgraded to duplex conductors are shown below:
Stage
Transmission Project
New 400kV double circuit Otahuhu – Whakamaru line
New 220 kV double circuit Wairakei – Atiamuri – Whakamaru line (string one side
only)
1
Duplex 220 kV Tokaanu – Whakamaru A&B lines
Duplex 220 kV Bunnythorpe – Haywards A&B lines
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead)
New 400 kV double circuit Bunnythorpe – Whakamaru line
2
Tap Rangipo 220 kV bus onto Bunnythorpe-Tokaanu 220 kV A&B lines11,12
New 400 kV double circuit Whakamaru – Pakuranga
String second side of 220 kV Wairakei – Atiamuri – Whakamaru double circuit line
New 220 kV double circuit Taumarunui-Whakamaru line
3
Connect 400 kV double circuit line constructed in stage 1 into Huntly
New 220 kV single circuit Whakamaru – Wairakei line
Bond 220 kV Otahuhu – Whakamaru C line to create a single circuit
Table 4-9: 400 kV Grid Development Plan (Generation Scenario 3)
The stage 1
grid augmentation plan for this scenario is identical to those developed
under scenarios 1 & 2. Similarly, stage 2
development is identical to that developed
under Scenario 2.
In stage 3, a second double circuit 400 kV transmission line from Whakamaru to
Auckland will have to be constructed. This is because in Generation Scenario 3, very
little new generation is projected north of Whakamaru compared with generation
scenarios 1 and 2. Consequently, more transmission capacity into Auckland will be
required compared with other generation scenarios. Additional 220 kV lines will be
required into Bay of Plenty via the Wairakei ring, similar to the requirement under
scenarios 1 and 2. The 400 kV line built in stage 1 will need to be diverted to Huntly
power station by constructing a short section of 400 kV double circuit line for
dispatching generation from Huntly. The Huntly-Otahuhu section of the existing 220
kV Otahuhu - Whakamaru C line could be decommissioned in this stage.13 Also in
stage 3, a new small section of 220 kV line from Taumarunui to Whakamaru will need
to be built.
11 This development assumes that the Tangiwai – Rangipo section of the Bunnythorpe – Tokaanu A&B
lines are decommissioned.
12 The need for decommissioning will be assessed closer to the time depending on the condition of the
asset and the generation developments (especially wind generation) in the region.
13 The need for decommissioning will be assessed closer to the time depending on the condition of the
asset and the generation developments (especially wind generation) in the region.
Part III – Analysis of Options for Meeting the Investment Need
29
The ultimate augmentation plan based on 400 kV option for Scenario 3 is shown in
Figure 4-8.
Part III – Analysis of Options for Meeting the Investment Need
30
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
PAK
OTA
OTA
TAK
GLN
HLY
HLY
HAM
WPA
MOK
MTI
WKM
WKM
TRK
ATI
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
BPE
N
400 KV Grid
LI
L
WI
HAY
220 KV Grid
Figure 4-8: 400 kV Grid Development Plan 2040 for Generation Scenario 3
Part III – Analysis of Options for Meeting the Investment Need
31
4.5.5 400 kV Grid Development Plan for Generation Scenario 4 (Southern
Hydro) from 2010-2040
The major projects, new lines that are to be built and those existing 220 kV lines that
are to be upgraded from single conductor to duplex conductors for this generation
scenario is shown below:
Stage
Transmission Project
New 400kV double circuit Otahuhu - Whakamaru line
New 220 kV double circuit Wairakei – Atiamuri – Whakamaru line
1
Duplex 220 kV Tokaanu – Whakamaru A&B lines
Duplex 220 kV Bunnythorpe – Haywards A&B lines
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead)
2
New HVDC link of capacity 600 MW from the South Island into Auckland
Duplex 220 kV Atiamuri – Tarukenga A line
3
Upgrade the capacity of new HVDC to Auckland from 600 to 1200 MW
New 220 kV double circuit Otahuhu – Penrose line
Table 4-10: 400 kV Grid Development Plan (Generation Scenario 4)
The stage 1 grid augmentation plan for this scenario is identical to those developed
under scenarios 1, 2 & 3.
In this generation scenario there is an increasing generation deficit in the North
Island from 2010 onwards. With the upgrade of the capacity of the existing inter-
island HVDC link to 1400 MW, this deficit can be supplied up to a point where n-1
security under generation contingencies can no longer be maintained. In stage 2 of
this upgrade plan, a new HVDC link is required to import power from the South
Island. This link is planned to inject power directly into Auckland. Reinforcement of
the 220 kV grid into Bay of Plenty and through the Wairakei ring will also be required.
In stage 3 of this grid augmentation plan, the capacity of the new HVDC link between
the South Island and Auckland will have to be increased. This is once again driven by
insufficient generation capacity in the North Island for ensuring the supply security.
The 220 kV grid between Otahuhu and Penrose will have to be reinforced to cater for
the increased demand north of Otahuhu.
The ultimate augmentation plan based on 400 kV option for Scenario 4 is shown in
Figure 4-9.
Part III – Analysis of Options for Meeting the Investment Need
32
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
OTA
TAK
GLN
HLY
To South
Island
HAM
WPA
MOK
MTI
WKM
WKM
TRK
ATI
400 KV Grid
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
N
LI
L
WI
HAY
220 KV Grid
Figure 4-9: 400 kV Grid Development Plan 2040 for Generation Scenario 4
Part III – Analysis of Options for Meeting the Investment Need
33
4.5.6 400 kV Grid Development Plan for Generation Scenario 4 (Reduced
Demand) from 2010-2040
The major projects, new lines that are to be to be built and existing 220 kV lines that
are to be upgraded from single conductor to duplex conductors for this generation
scenario is shown below:
Stage
Transmission Project
New 400kV double circuit Otahuhu - Whakamaru line
New 220 kV double circuit Wairakei –Ohakuri-Atiamuri – Whakamaru line
1
Duplex 220 kV Tokaanu – Whakamaru A&B lines
Duplex 220 kV Bunnythorpe – Haywards A&B lines
Auckland cross isthmus reinforcement with new 220 kV circuit (cable or overhead)
Loop in one circuit of Otahuhu-Whakamaru 400 kV line at Huntly
Tap the 220 kV Huntly-Stratford circuit at Taumarunui
Duplex 220 kV double circuit Bunnythorpe-Tokaanu . Tap Rangipo 220 kV bus
2
onto Bunnythorpe-Tokaanu A&B lines
Duplex 220 kV Bunnythorpe-Tangiwai-Rangipo section of Bunnythorpe-Wairakei
A line
Duplex 220 kV Rangipo-Wairakei section of Bunnythorpe-Wairakei A line
Duplex 220 kV Atiamuri-Tarukenga A line
3
Duplex 220 kV Wairakei-Ohaaki-Atamuri circuit
Table 4-11: 400 kV Grid Development Plan 2040 for Generation Scenario 5
The stage 1 grid augmentation plan for this scenario is identical to those developed
under scenarios 1-4.
In stage 2 one circuit of the 400 kV line built in stage 1 will need to be diverted to
Huntly power station by constructing a short section of 400 kV double circuit line.
This will be required for dispatching the increased generation from Huntly and the
Taranaki region. Increased Taranaki generation under this scenario necessitates
sectionalising the 220 kV Huntly-Stratford circuit by tapping at Taumarunui. It is
necessary to strengthen the system between Bunnythorpe and Whakamaru. Rangipo
is tapped onto the two Bunnythorpe-Tokaanu circuits and the capacity of the three
circuits out of Bunnythorpe is increased.
In stage 3, increased Wairakei generation results in the requirement for
reinforcements of the 220 kV grid into Bay of Plenty and through the Wairakei ring.
The ultimate augmentation plan based on 400 kV option for Scenario 5 is shown in
Figure 4-10.
Part III – Analysis of Options for Meeting the Investment Need
34
MDN
= Existing Lines
SVL
= New Lines
BRB
ALB
= Reconstructed or
Upgraded Lines
= Potential Lines for
HEN
Decommissioning
= HVDC
SWN
PEN
OTA
OTA
TAK
GLN
HLY
HLY
HAM
WPA
MOK
MTI
WKM
WKM
TRK
400 KV Grid
ATI
EDG
KAW
OKI
OHK
TMN
ARA
WRK
WHI
TKU
RDF
RPO
WTU
TNG
NPL
SFD
SPL
BRK
BPE
LIN
L
WI
HAY
220 KV Grid
Figure 4-10 400 kV Grid Development Plan 2040 for Generation Scenario 5
Part III – Analysis of Options for Meeting the Investment Need
35
4.6 Assessment of 400 kV HVAC Grid Upgrade Plan
4.6.1 System Security, Asset Availability and Flexibility
The 400 kV grid upgrade plan can be constructed to deliver equivalent outcomes to
the 220 kV option when assessed against System Security and Asset Availability
criteria. The flexibility of the 400 kV option to cater for a range of possible future
demand and generation patterns is also equivalent to the 220 kV option. The criteria
that provide a point of difference between 220 kV and 400 kV options are therefore
environmental and economic.
4.6.2 Environmental Considerations
The 400 kV option, when compared to 220 kV or 330 kV options, will require
substantially fewer new transmission lines to be constructed over the study period
out until 2040. With fewer line routes required for 400 kV transmission, the
environmental impact of transmission corridors, particularly those entering Auckland
city will be better contained than continuing with 220 kV developments.
While tower heights are clearly a sensitive issue for communities, on balance
Transpower considers that there are environmental benefits of having fewer high
capacity lines with higher towers as opposed to more low capacity lines with lower
height towers.
The choice of 400 kV as the main backbone voltage also reduces system losses
substantially. The average difference in peak system losses between 220 kV and
400 kV development plans, across all five generation scenarios at 2040 is estimated
as 50 MW.
4.6.3 Conclusions
A development plan based on introducing a 400 kV HVAC backbone into the
transmission system will meet the needs of New Zealand’s demand growth across a
range of possible generation futures.
A 400 kV network will provide satisfactory security of supply outcomes and would
require substantially fewer new transmission lines to be constructed, particularly into
the high demand growth areas such as the upper North Island.
With fewer lines established in corridors of high power transfer, the environmental
impact of a 400 kV development plan will be lower than that of an equivalent capacity
220 kV development plan.
Finally, a 400 kV HVAC development plan is expected to deliver substantially higher
national benefits due to lower capital costs and lower transmission losses than a 220
kV development, as detailed in Part IV of this submission.
4.7 330 kV HVAC Development
This option considers adopting 330 kV as the main core grid voltage for the future
long term development of the New Zealand transmission system, augmenting the
transmission capacity of the present 220 kV system.
Part III – Analysis of Options for Meeting the Investment Need
36
This option retains many parts of the network at 220 kV, especially where generating
stations are already connected at that voltage or for regional supply only. The 220 kV
network will also be retained where the expected transmission along the corridor is
substantially small and does not warrant upgrading to a higher voltage.
One major driver as well as the attraction of the 330 kV option was the perceived
possibility of physical modification of the existing 220 kV transmission lines to be
operated at 330 kV. However, detailed investigations showed that significant rebuild
is required for such a conversion and in many cases it is not practical to convert 220
kV lines for operation at 330 kV. The issues that make upgrading the existing 220 kV
lines to 330 kV impractical are:
•
The foundations will have to be strengthened or replaced as existing
foundations are inadequate for the heavier loading required for 330 kV
lines.
•
If existing towers are to be re-used, a large number of temporary by-pass
lines will have to be built while existing towers are modified or relocated
and new conductors are installed to maintain security of supply.
•
The existing 220 kV flat-top towers have insufficient strength to sustain
the loads associated with a major upgrade of capacity. The lines would
be limited in their current carrying capacity which in turn forces the choice
of more, lower capacity lines as opposed to fewer high capacity lines.
The existing clearance levels of the 220 kV lines are also likely to be
insufficient to cater for 330 kV operation.
•
Some of the existing tower steel is more than 50 years old. Even though
these towers may be reused, it is likely that ageing and distortions while
in service will increase the cost of recycling. Further, the compatibility of
the strength of steel used in the old towers with modern tower designs
needs to be re-assessed.
•
All of the above points confirm that reusing the existing tower line
infrastructure for 330 kV in infeasible and that the lines would need to be
rebuilt to cater for a standard 330 kV performance specification.
•
Long continuous line outages will be required during the course of
conversion, with the associated risk that electricity supply to customers
will be interrupted.
•
Any such upgrades would not be able to be achieved under Transpower’s
existing use rights under the Electricity Act 1992. Therefore the 330 kV
option offers no advantage in terms of avoiding the need to acquire
property rights and consents under the Resource Management Act for
rebuilding the existing towers.
Preliminary costing studies have shown that there would be no cost advantage in
upgrading existing lines to 330 kV compared with construction of new lines at 330 kV.
4.7.1 System Security, Asset Availability and Flexibility
System Security, Asset Availability and Flexibility of the 330 kV option will be similar
to that discussed in Section 3.3, 220 kV HVAC Development.
Part III – Analysis of Options for Meeting the Investment Need
37
4.7.2 Environmental Considerations
This option provides similar advantages as the 400 kV option in terms of the number
of routes required, and will limit potential adverse effects to a defined transmission
easement, at least in the short term. However, over a long time period, 330 kV
development will naturally require greater transmission routes than 400 kV
development. Increase in the operating voltage to 330 kV from what is currently
being used (i.e. 220 kV) is also likely to raise community concern and opposition.
4.7.3 Conclusion
330 kV AC was only initially considered as an option because it was perceived that
the existing 220 kV lines could be easily converted to 330 kV AC operation.
Subsequent investigations showed that upgrading of the 220 kV lines for 330 kV
operation essentially require the lines to be rebuilt. Furthermore there is no cost
advantage for rebuilding the existing lines when compared to constructing a new line.
If new lines are to be built, the past experience and high level economic analysis
have shown that the new voltage to be migrated should be approximately twice the
present voltage. Hence 330 kV is considered to be too low to deliver long run
benefits, for adoption as the new core grid transmission voltage.
Because of the above reasons, it was concluded that 330 kV will not provide a
suitable transmission option for long term upgrade of the transmission grid.
4.8
500 kV HVAC Development
Transpower has carried out detailed assessment of the viability of using 500 kV as
the next voltage level for the long term development of the New Zealand high voltage
grid, augmenting the capacity of the existing 220 kV grid.
Experience shows that, if there is a need to migrate to another system voltage, the
next system voltage level should be about twice the existing voltage level. With the
current principal transmission voltage in New Zealand being 220 kV, this suggests
voltages of either 400 kV or 500 kV. The ultimate choice is a function of a number of
factors including, the distance over which power transfers are required and the load
density.
The electricity demand in North Island accounts for two thirds of the demand of New
Zealand14 and about one third is consumed in Auckland alone. Over the 40 year
planning period, transfers on a number of corridors will require reinforcement
depending on the assumed generation. The forecast corridor transfers are shown in
Figure 4-11. Figure 4-11 also shows typical transfer capabilities of circuits at 220 kV,
400 kV and 500 kV although these may vary slightly depending on the choice of
conductor and overhead line configuration15 (ref: Peer review of choice of voltage for
development of the New Zealand Grid).
14 The remaining one third of the demand is associated with the South Island with a large proportion
consumed in Christchurch.
15 “Peer Review of Choice of Voltage for Development of the New Zealand Grid”– PB Power February
2004.
Part III – Analysis of Options for Meeting the Investment Need
38
3500
3300 MW - 2040 Whakamaru-Auckland maximum corridor transfer
Variance in length of
3000
circuits in circuits in
North Island
2500
2000
Circuit (MW)
r /
500 kV
1500
1300 MW - 2040 Bunnythorpe-Whakamaru maximum corridor transfer
r Transfe
e
1100 MW - 2040 Stratford-Whakamaru maximum corridor transfer
1000
1100 MW - 2040 Maximum circuit transfer
400 kV
Pow
500
220 kV
0
50
100
150
200
250
300
350
400
Distance (km)
Figure 4-11 North Island - transfer capability at various voltage levels compared to
expected corridor and circuit transfers.
In the North Island, the Whakamaru-Otahuhu, Bunnythorpe-Whakamaru and
Stratford-Whakamaru corridor transfers are forecast to increase to approximately
3,300 MW, 1,300 MW and 1,100 MW respectively over the planning period. The
number of additional circuits required to secure these transfers under contingency
conditions is shown in Table 4-12.
Corridor
220 kV
400 kV
500 kV
Whakamaru-Otahuhu 8
4
3
Bunnythorpe-Whakamaru 416 2 2
Stratford-Whakamaru 417 2 2
Table 4-12 Requirements for additional circuits to secure corridor transfers by 2040
Therefore, while there may be an argument for the introduction of 500 kV to
accommodate transfers from Whakamaru-Otahuhu, the capacity would be overly
high for transfers required in the Bunnythorpe-Whakamaru and Stratford-Whakamaru
corridor. High level economic analysis has also shown that 500 kV development
options will yield lower economic benefits compared to 400 kV developments.
16 Comprises 2 x Bunnythorpe-Whakamaru circuits and 2 x Bunnythorpe-Rangipo circuits
17 Comprises 1 new double circuit and 1 rebuilt double circuit with heavier construction
Part III – Analysis of Options for Meeting the Investment Need
39
4.8.1 System Security, Asset Availability and Flexibility
System Security, Asset Availability and Flexibility of the 500 kV option will be similar
to that discussed in Section 3.3, 220 kV HVAC Development.
4.8.2 Environmental Considerations
Capacity is considerably in excess of that required to meet reasonable transmission
requirements and will result in increased tower heights and easement area (to
accommodate EMF levels). This option provides similar advantages as the 400kV
option in terms of the number of routes required, and will limit potential adverse
effects to a defined transmission easement. Overall effects within this easement will
be greater than the 400kV option, without any real advantage.
4.8.3 Conclusions
The capacity offered by the 500 kV transmission lines, while under some generation
scenarios would be suitable for high power transmission corridors, the utilisation
would be small for many line corridors considered with the planning horizon until
2040. Hence 500
kV is not considered as the preferred voltage for future
development of the New Zealand transmission system.
4.9 HVDC Link between South Island and Auckland
Transpower operates an HVDC link between Benmore in the South Island and
Haywards in the North Island. Equipment forming the HVDC link includes:
•
Converter stations at Haywards and Benmore. These stations convert
electricity between HVAC and HVDC;
•
Overhead transmission lines between Benmore and Fighting Bay in the
South Island and Oteranga Bay and Haywards in the North Island.
•
Undersea cables between Fighting Bay and Oteranga Bay which are laid
across the Cook Strait.
The HVDC link is “bi-polar” which means that the power transferred between the
North and South Islands can be transmitted through one or two HVDC poles. Pole
1 of the HVDC link was commissioned in 1964 and consists of mercury-arc
converters. Pole 2 was commissioned in 1992 and is constructed using newer
thyristor technology. The mercury-arc pole is nearing the end of its economic and
physical life and is due for replacement within the next ten years. Therefore, the
most viable option for extending the HVDC link to Auckland is to decommission
pole 1 at Haywards, construct a new HVDC transmission line from Haywards to
Auckland and establish a new HVDC pole in Auckland. The new HVDC pole from
Benmore to Auckland would be rated at 350 kV and 700 MW in order to match the
existing thyristor based pole 2 at Haywards.
The HVDC link between the South Island and Auckland was assessed as follows:
4.9.1 System Security
The HVDC alternative would provide up to 700 MW of “non-firm” additional
transmission capacity into the Auckland area. This capacity must be regarded as
non-firm because loss of the HVDC line from Benmore to Auckland (via
Part III – Analysis of Options for Meeting the Investment Need
40
Haywards) or failure of a single converter pole at either Auckland or Benmore will
result in the complete loss of 700 MW of power transfer into Auckland. This does
not provide a grid augmentation alternative comparable with the preferred HVAC
transmission option of 400 kV which would provide approximately 1000 MW of
firm capacity (1000 MW on each circuit, with a total capacity of 2000 MW18) into
Auckland.
The critical concern regarding HVDC augmentation is its inability to transport
power into Auckland during dry year periods in the South Island. Historically,
during dry years, power transmission through the HVDC link from the South Island
to the North Island reduces significantly. For extended periods during dry years,
power flows are often north to south. Figure 3.18 shows the HVDC transfer
southward during a period of low hydro inflows in 2001 in the South Island
(indicated as negative power flows). If southward power flows across the HVDC
link occur at the time of high system demand, as evidenced in 2001, then an
HVDC upgrade will provide no security of supply enhancement to the Auckland
region during dry years.
It is not considered a feasible grid augmentation option to implement a
transmission alternative that will not meet the peak demand requirements of a
region under a realistic generation scenario (in this case, dry year conditions).
Therefore, even if an HVDC alternative was implemented, HVAC grid
augmentation into Auckland would still be required to provide a secure power
supply. For this reason, HVDC augmentation between the South Island and
Auckland was not considered to be a realistic transmission alternative to solve the
security of supply concerns into the upper North Island.
H VD C N o rth T ran sfe r D u rin g L o w H yd ro In flo w P e rio d s
2 0 0
1 0 0
0
2
1
3-
5
7
9-
8
3
-
-
-
-J
0-
A
A
A
A
A
u
J
ug
u
ug
u
ug
l
u
g
g-
-0
l-
-0
-0
-0
01
-0
-1 0 0
1
01
1
1
1
1
-2 0 0
MW
-3 0 0
-4 0 0
-5 0 0
-6 0 0
Da te / Tim e
Figure 4-12: HVDC Power flows during a typical dry year (2001)
18 While a new double circuit 400 kV line will provide 1000 MW of firm and 2000 MW of total thermal
capacity, voltage stability limitations will reduce the actual power transferable into Auckland to a lesser
quantity. The actual quantity will depend on the generation and reactive support that is established in
the area.
Part III – Analysis of Options for Meeting the Investment Need
41
4.10 HVDC Link between Whakamaru and Otahuhu - Classical
Configuration
In consideration of HVDC as an alternative to HVAC transmission between Otahuhu
and Whakamaru, Transpower assessed a number of HVDC transmission
configurations of differing operating voltages and transfer capacities. The most
suitable HVDC option is a 350 kV link which could provide a secure and reliable
supply with 1000 MW of firm capacity. The link would consist of a double bi-pole
arrangement with each pole of the two converter stations (one at Whakamaru and
the other at Otahuhu) rated to 500MW.
The choice of a 350 kV HVDC pole design rated at 500MW would allow the use of
proven technology. Modular designs with this rating are available from a number of
manufacturers and would likely be offered at competitive prices.
The double bi-pole option was assumed to be implemented in two discrete stages.
Stage 1
•
Completion of the entire transmission line and the short length of
underground cable within Auckland urban area.
•
Installation of 1000 MW, 350 kV bi-pole converter stations, at Whakamaru
and Otahuhu.
Stage 2
•
The ultimate design would be achieved by installing another 1000MW,
350 kV bi-pole converters, at Whakamaru and Otahuhu. This would
augment the capacity of the HVDC link to1000 MW of firm capacity.
This ultimate design which includes the independent operation of two bi-poles
between Whakamaru and Otahuhu is shown in Figure 4-13.
Part III – Analysis of Options for Meeting the Investment Need
42
Otahuhu 220 kV Bus
AC
Filters
500 MW
500 MW
500 MW
500 MW
DC Cable
section
DC
Overhead
line
Bipole 2
Bipole 1
500MW
500 MW
500MW
500 MW
Conductor polarity
Whakamaru 220 kV Bus
Negative Pole
Neutral/Metallic Return
Positive Pole
Figure 4-13: Schematic for 350 kV HVDC Transmission Link Between Whakamaru and
Otahuhu
Establishing a 350 kV double bipole HVDC link between Whakamaru and
Auckland was assessed follows:
4.10.1 System Security
The HVDC option described above provides sufficient capacity to maintain supply
security into the Auckland region in a level comparable to that provided by all HVAC
transmission options.
Part III – Analysis of Options for Meeting the Investment Need
43
4.10.2 Asset Availability
Considering the transmission lines in isolation (i.e. apart from the terminal
equipment), the double bi-pole HVDC transmission line is likely to have an equivalent
availability to that offered by the proposed 400 kV HVAC transmission line.
However, the AC-DC-AC converter stations do not provide the same reliability as
400/220 kV HVAC transformers. Converter stations are inherently complex and
contain a large number of components which can contribute to partial or total
converter station failure. Further, there are a significant number of items common to
both poles of an HVDC bi-pole scheme, leading to increased risks of common-mode
failures.
In summary, the HVAC system will provide an overall higher level of asset availability
and therefore system reliability into the Auckland region. While HVDC remains a
potential fit for purpose solution, the risks of reduced reliability - in particular
converter station failure - must be taken into consideration in the decision making
processes.
4.10.3 Economic Benefit
Because of the high capital investment required for HVDC converter stations,
development of the converter capacity in several stages as described above will
provide significant economic benefits.
However, even with the staged development, when the net present value of the
HVDC versus HVAC costs are considered, the HVDC solution is found to be
significantly more expensive compared to the HVAC options.
4.10.4 Environmental Considerations
The DC option operates at 350 kV and thereby offers similar advantages to the 330
and 400 kV AC voltage options in terms of the overall number of transmission line
routes. Tower numbers are also likely to be similar.
Although both the AC and DC options will be required to comply with ICNIRP
guidelines pertaining to electric and magnetic fields, overall levels from DC lines
enable reduced height of towers compared to equivalent voltage AC options. Visual
effects (and associated effects on tourism and recreational values), although
subjective, would arguably be less than the AC option.
The DC technology also requires increased density of structures at Whakamaru and
Otahuhu, with associated effect on local amenity. Adverse effects of such termination
structures are site specific and can most likely be mitigated within existing industrial
landscapes at Whakamaru and Otahuhu sites.
4.10.5 Timing
HVDC systems are inherently complex and need to be designed carefully, taking into
account the variability of the operating conditions and the dynamic performance of
the connected power system. Typically, the lead time for construction, form the time
of awarding the contracts, ranges from 3 to 4 years. However, the developments are
also associated with significant pre-tendering technical investigations and therefore
the total lead time required would be in the order of 5 – 6 years.
Part III – Analysis of Options for Meeting the Investment Need
44
Therefore, if HVDC developments are to be used for providing the supply security to
the Auckland region by 2010, investigation and construction time needs to be
significantly compressed. Such expediency will result in significant commercial and
technical risks to the development project.
4.10.6 Flexibility
HVDC options provide less flexibility for future grid expansion and will continue to be
associated with higher level of capital investments compared to the HVAC options.
One significant disadvantage of the HVDC options is that, once an HVDC link is
established, the opportunities for “tapping off” (i.e connecting) at different points in
order to accommodate future grid developments become very limited. At present, it is
the generally accepted view that HVDC transmission linking more than three
terminals is not technically sound. While a point-to-point HVDC link can be
augmented at a significant cost to make a three terminal link for tapping off at a
single point between its original terminals, it does not allow for any further tapping off.
In a future with deregulated generation investments, whose locations are significantly
uncertain, such a limitation in the flexibility of making new connections to the grid is a
significant concern.
4.10.7 Conclusions
Overall, the adoption of an HVDC transmission backbone would deliver a more
expensive, less reliable and relatively inflexible transmission system in the long run
than a National Grid supported by an interconnected HVAC transmission network.
More details of this analysis are contained in the supporting document titled
“Comparison of HVDC and HVAC Grid Upgrade Alternatives – May 2005”.
4.11 HVDC Link between Whakamaru and Otahuhu – HVDC
Light Configuration
This option uses voltage sourced converters consisting of insulated gate bipolar
transistors (IGBT) as switching devices rather than thyristors. The power handling
capability of IGBTs is not as large as thyristors and with present technology the Pole
capacity is limited to a maximum of about 330MW.
At present technology limitations also require underground cable(s) for the entire
length of transmission link.
Similar to HVDC Classical option the transmission capacity of HVDC light option can
be increased in several stages. The circuit configurations for a two stage
development are shown in Figure 4-14.
HVDC Light also has the advantage over the HVDC Classic option that converter
stations are more compact due to the reduced size of filters. However, the
disadvantages are that converter losses are much higher due to higher switching
frequencies compared to classic HVDC, and the higher transmission losses due to a
lower DC operating voltage.
Part III – Analysis of Options for Meeting the Investment Need
45
Whakamaru
Otahuhu
500 MW
Stage 1
Whakamaru
Otahuhu
500 MW
Stage 2
Whakamaru
Otahuhu
500 MW
Figure 4-14: Circuit Configuration Stages 1 & 2 HVDC Light Transmission
System 1000 MW Firm
Stage 1
•
Installation of 2 x 500 MW converters in year 2010
Stage 2
•
Installation of 1 x 500 MW as required under the corresponding
generation scenarios.
Establishing a HVDC Light between Whakamaru and Auckland was assessed
follows:
4.11.1 System Security
The HVDC light option configuration as shown in the above figure will provide (n-1)
security to the Auckland load, at a level of reliability similar to that provided by the
HVAC options.
Part III – Analysis of Options for Meeting the Investment Need
46
4.11.2 Asset Availability
With the present state of technology, the HVDC Light option can only work with
underground cables and the maximum operating voltage is below 200 kV thus
requiring many cables. This means total undergrounding with multiple cables and
multiple routes.
Underground land based cables are not as reliable as overhead lines options due to
the large number of joints in land cables and the substantial mean time to repair any
cable failures. The number of joints is high due to the practical length of cable
sections that can be transported and installed using vehicles in New Zealand in
roads. Furthermore, fault location and repair times would generally be higher than for
overhead conductors.
4.11.3 Environmental Considerations
The HVDC Light option is visually very attractive due to the entire length of line being
undergrounded. Converter stations can be compact (as compared with the Classic
HVDC options). This means that the land area required for the converter stations
may be less than for the classic HVDC options.
Potential adverse impacts of HVDC light option are similar to other underground
cables, including earthworks and vegetation removal during the construction phase,
and longer term requirements to maintain areas along the cable length free of
vegetation.
4.11.4 Timing
Implementation of the HVDC Light option will require a typical of 28-36 months to
complete, from the date of issuing a contract. A full length cable solution will involve
an easement acquisition process and cable installation, which will likely to take a
longer time than the construction of overhead transmission lines.
4.11.5 Future Flexibility
HVDC light can be applied as a new link at any time in the future. However to meet
N-1 security levels and a level of reliability comparable to the HVAC options it is
probable that any new link to another location would need to be duplicated. This
increases costs, and given the already high cost of converters, cables and losses
make it unlikely that new HVDC Light links would be attractive.
4.11.6 Economic Benefits
The cost of HVDC Light transmission development must consider the cost of
undergrounding the cables over the total length of the route. The cost of supply of
HVDC light cables is estimated to be in the order of $224 million per 500 MW HVDC
Light link. The installation cost is expected to be more than the cable cost since
trenching rather than ploughing would be needed. Thus for three HVDC Light links,
the total installed cost of cables and converters would be approximately over $2.1
billion.
Part III – Analysis of Options for Meeting the Investment Need
47
4.11.7 Conclusion
Overall, the adoption of an HVDC light transmission backbone would deliver a very
expensive and unreliable transmission system in the long run than a National Grid
supported by an interconnected HVAC transmission network.
4.12 Underground Transmission Options
Extra high voltage (EHV) cables are increasingly being used worldwide to supply
electrical power for large cities and metropolitan areas. This is due to the increasing
difficulty in obtaining overhead transmission line routes through high density built up
areas. Other special reasons include, entry to substations, crossing other overhead
lines, safety reasons at airports, land value enhancement and social/environmental
concerns which require undergrounding.
Transpower has investigated a range of issues associated with partial or complete
undergrounding of the proposed 400 kV AC transmission link between Whakamaru
and Otahuhu substations.
4.12.1 Reliability
The reliability of the underground cable systems (for 220 kV and above) was
investigated and compared with the overhead transmission in terms of expected
performance including failure rates, outage times and availability due to forced
outages.
If the present grid availability is to be maintained then the failure rates and outage
times for 400 kV links would have to be to be equal to or better than those for the
existing 220 kV lines.
There is a very high level of uncertainty in the estimation of the failure rates for 400
kV cables because of the small number of circuit kilometres installed and recent
changes in technology with the introduction of XLPE type cables at this voltage.
Repair times for faults on cables, joints and terminations are much longer than for
overhead lines and at best will take between 10 and 19 days. This assumes that the
contracting cable jointers would be immediately available from overseas, that spares
were immediately available in New Zealand and the site is accessible and fault easily
located.
Even with optimistic assumptions on failure rates and outage durations the
availability of a 400 kV cable circuit will be significantly worse than for an overhead
line when transmission over long distances is concerned. The expected levels of
reliability are far too low to consider a complete underground cable system between
Whakamaru and Otahuhu is a feasible transmission option.
4.12.2 Economic Benefit
Financial cost of underground transmission between Otahuhu – Whakamaru would
be significantly expensive compared to overhead transmission. The costs would be in
approximately 10:1 ratio. The costs are further increased by the need to provide
intermediate stations at approximately 50 km intervals along the cable route for cable
charging current compensation.
Part III – Analysis of Options for Meeting the Investment Need
48
Operation and maintenance of such an underground cable system will depend on
availability of skilled cable jointers and specialised equipment. Therefore, operating
costs would also be significantly higher compared to overhead transmission.
4.12.3 Environmental Considerations
The environmental impacts of underground cables are most obviously associated
with short term effects during the construction phase. These include earthworks,
vegetation removal and general construction nuisance. Longer term effects are
limited to the need to maintain areas without vegetation along the cable length.
Selection of a cable route that avoids sensitive ecological and social environments is
equally relevant to cable locations as overhead lines. As with overhead cables, public
exposure to electrical and magnetic fields will be required to comply with ICNIRP
guidelines.
While, the visual impact of underground transmission is minimal, easements need to
be maintained throughout the route and loss of use of land (at least partially) can not
be avoided. Furthermore, excavations associated with installation of underground
cables are more likely to expose sites of cultural or archaeological significance during
the installation phase, thereby holding up work until appropriate approvals are
obtained.
4.12.4 Timing
There would be a longer lead time in manufacturing and procuring long lengths of
cable. Availability of skilled cable jointers and specialised equipment for installation
will also slowdown the progress of the project compared to building an overhead line.
Therefore, it is unlikely that an underground installation can be completed in time (i.e.
2010) for ensuring the security of supply to Auckland load.
4.12.5 Flexibility
Compared with overhead lines, operational issues associated with cable
transmission such as, the need to match compensation with load and harmonic
impedance resonance problems exacerbated by the higher capacitance of cables,
could significantly limit the operational flexibility of a long underground transmission
system compared to overhead transmission.
4.12.6 Conclusion
A review of available information and advice from its consultants confirm
Transpower’s views that installing underground cables at 400 kV AC from
Whakamaru to Otahuhu is not a technically fit-for-purpose solution. The reliability of
the underground cable route is far less than what is required for a high security
backbone of the core grid.
The cost of undergrounding will also be substantially higher than overhead.
Transpower estimates that underground cabling would be approximately ten times
the cost of overhead line.
Part III – Analysis of Options for Meeting the Investment Need
49
4.13 Summary of Transmission Options
The following summarises the results from the assessment of transmission options:
220 kV AC
220 kV HVAC development could meet the future demand growth in the North Island
and would be a credible approach for the future long term development of the core
transmission grid in the North island. However, 220 kV development would require a
number of transmission lines to be build, especially between Whakamaru and
Auckland under some generation scenarios. Given the difficulty in obtaining
transmission corridors for building new lines, and considering the environmental
impact, the ability to implement such a plan in long term is a concern.
330 kV AC
Conversion of the existing 220 kV lines to operate at 330 kV will require significant
changes to the construction of the existing towers, foundations and replacement of
the existing conductors. Significant outages would also be required which would
place security of supply to the upper North Island at risk. On this basis conversion of
existing lines is considered impractical and new lines would be required to be
constructed to carry any new 330 kV infrastructure. If new lines are to be built,
system studies have shown that the increase in voltage does not provide a
substantial change in the number of additional lines required, particularly into the
upper North Island. Transpower therefore considers that migration of the core
network to 330 kV is too low for to provide sufficient technical and economic benefits
to warrant further consideration.
400 kV AC
400 kV HVAC development could meet the future demand growth in the North island
and would be a credible approach for the future long term development of the core
transmission grid in the North island. A 400 kV development option would enable the
future core grid transmission requirements to be met using substantially fewer lines
than 220 kV and 330 kV options.
500 kV AC
500 kV HVAC development could meet the future demand growth in the North island
and would enable the future core grid transmission requirements to be met using only
a few lines. Although 500 kV is a viable transmission voltage it provides significant
transmission capacity in excess of that required for most of the transmission corridors
in the North Island within the planning horizon. Furthermore it has no advantages
over a 400 kV solution but it has a number of disadvantages. Consequently, 500 kV
is not considered as the preferred voltage for future development of the New Zealand
transmission system.
HVDC
An HVDC link was considered as a transmission alternative to high voltage AC
options, but the lower reliability, the inflexibility for future developments and higher
costs of the HVDC make the high voltage AC options a more suitable option.
Underground Cables
Part III – Analysis of Options for Meeting the Investment Need
50
A review of available information and advice from its consultants confirm
Transpower’s views that installing long lengths of high voltage underground cables
from Whakamaru to Otahuhu is not a technically fit-for-purpose solution. The
reliability of the underground cable route is far less than what is required for a high
security backbone of the core grid and the cost of undergrounding will also be
substantially higher than an overhead option.
5 Alternatives
to
Transmission
The EGRs define the term “alternatives to transmission” as:
“ :
alternatives to investment in the grid, including investment in local generation,
energy efficiency, demand-side management and distribution network
augmentation…” Transpower has considered the following four broad categories of alternatives to
transmission as part of its analysis of the proposed 400kV AC investment:
• electricity
substitutes
• generation
alternatives
•
energy efficiency alternatives
•
demand-side management alternatives
These four categories are described below:
5.1 Electricity substitutes
Natural gas reticulation is an example of an electricity substitute.
On a smaller scale (e.g. by increasing domestic reticulation) gas could defer
transmission, but in some situations (e.g. when building a new industrial plant) gas
could be used instead of transmission. To be considered as a feasible transmission
alternative for the upper North Island, Transpower notes that future gas supplies
would need to be certain and gas transmission infrastructure would need to be
augmented to deal with the significant increase in volume. Future gas supplies are
not certain and there are no committed projects to switch consumers from electricity
to gas, so Transpower considers that this cannot be relied upon as a transmission
alternative.
Transpower has neither the information nor expertise to properly evaluate natural gas
reticulation, or other electricity substitutes. Therefore they are not discussed further in
this document.
5.2 Generation Alternatives
The potential for large scale base-load generation plant to be a transmission
alternative is assessed by considering the market development scenarios. For more
specific generation proposals, Transpower used a Request for Information (RFI)
Part III – Analysis of Options for Meeting the Investment Need
51
process to obtain details of proposals directly from the industry. More detail on the
RFI is included in Section 4.5.
The market development scenarios include various views of the major base-load
generation plant that may develop in the future, including in the upper North Island.
Because the scenarios have been developed to represent the extremes of likelihood,
it is assumed that at least some of them reflect the maximum amount of new
generation that is likely to appear in the upper North Island. The market development
scenarios include the following new generation:
New Installed Capacity
Auckland and North Isthmus Region
2,500
2010
2015
2020
2025
2030
2035
2,000
2040
1,500
MW
1,000
500
0
l
as
es
G
Coa
dro
abl
Hy
ew
w Demand
Ren
Lo
Figure 4-15: Cumulative new generation in the upper North Island
As a first step, the amount of demand growth that is forecast to be unserved in the
upper North Island was calculated. The following assumptions were made in the
calculations:
•
Demand growth is between the low and high growth estimates
•
The maximum load capability in the Auckland region is 2285MW
•
New generation is commissioned according to the market development
scenarios and is available for dispatch at a de-rated capacity to allow for
planned maintenance outages, in the case of thermal plant 84% of
installed capacity rating was assumed and in the case of wind
generation35% of installed capacity rating was assumed to be available.
This results in the following estimates of unserved energy for each market
development scenario:
Part III – Analysis of Options for Meeting the Investment Need
52
Unserved Energy Avoided by 400kV Development Plan
Unserved Energy Avoided by 400kV Development Plan
Gas Scenario
GWh
GWh
Coal Scenario
2,500
2,500
Low Demand Growth
Low Demand Growth
Medium Demand Growth
Medium Demand Growth
2,000
High Demand Growth
2,000
High Demand Growth
1,500
1,500
1,000
1,000
500
500
-
-
2005
2010
2015
2020
2025
2030
2035
2040
2005
2010
2015
2020
2025
2030
2035
2040
Unserved Energy Avoided by 400kV Development Plan
Unserved Energy Avoided by 400kV Development Plan
GWh
Renewables Scenario
GWh
Hydro Scenario
2,500
10,000
Low Demand Growth
Low Demand Growth
9,000
Medium Demand Growth
Medium Demand Growth
2,000
High Demand Growth
8,000
High Demand Growth
7,000
1,500
6,000
5,000
1,000
4,000
3,000
500
2,000
1,000
-
-
2005
2010
2015
2020
2025
2030
2035
2040
2005
2010
2015
2020
2025
2030
2035
2040
Unserved Energy Avoided by 400kV Development Plan
GWh
Low Demand Scenario
10,000
Low Demand Growth
9,000
Medium Demand Growth
8,000
High Demand Growth
7,000
6,000
5,000
4,000
3,000
2,000
1,000
-
2005
2010
2015
2020
2025
2030
2035
2040
Figure 4-16 – Graphs of unserved energy per market development scenario
As can be seen, there is unserved energy in all of the scenarios, indicating that there
is insufficient new generation emerging in the upper North Island to meet the forecast
demand growth.
Accepting that the market development scenarios represent reasonable extremes of
the potential new generation in the area, it can be concluded that large scale base-
loaded generation has already been considered as part of the analysis and cannot be
considered as a transmission alternative as well. This conclusion is also tested
economically in Section 1, where the cost of installing new transmission to avoid the
unserved energy is compared to the value of the unserved energy itself.
As a comparison, the same calculations have been undertaken using the Electricity
Commission’s market development scenarios, as published in their Statement of
Opportunities19:
19 Initial Statement of Opportunities, July 2005
Part III – Analysis of Options for Meeting the Investment Need
53
Their market development scenarios include the following new generation:
New Installed Capacity EC Scenarios
Auckland and North Isthmus Region
2,500
2010
2015
2,000
2020
2025
1,500
MW
1,000
500
0
s
o
Ga
Coal
and
ewables
Hydr
Ren
Low Dem
Figure 4-17: Cumulative new generation in the upper North Island in the Electricity
Commission scenarios
This new generation results in the following estimates of unserved energy for each of
the Electricity Commission’s market development scenarios:
Unserved Energy Avoided by 400kV Development Plan
Unserved Energy Avoided by 400kV Development Plan
EC Gas Scenario
GWh
EC Coal Scenario
GWh
2,500
2,500
Low Demand Growth
Low Demand Growth
Medium Demand Growth
Medium Demand Growth
2,000
High Demand Growth
2,000
High Demand Growth
1,500
1,500
1,000
1,000
500
500
-
-
2005
2010
2015
2020
2025
2030
2035
2040
2005
2010
2015
2020
2025
2030
2035
2040
Unserved Energy Avoided by 400kV Development Plan
Unserved Energy Avoided by 400kV Development Plan
GWh
EC Renewables Scenario
GWh
EC Hydro Scenario
2,500
2,500
Low Demand Growth
Low Demand Growth
Medium Demand Growth
Medium Demand Growth
2,000
High Demand Growth
2,000
High Demand Growth
1,500
1,500
1,000
1,000
500
500
-
-
2005
2010
2015
2020
2025
2030
2035
2040
2005
2010
2015
2020
2025
2030
2035
2040
Part III – Analysis of Options for Meeting the Investment Need
54
Unserved Energy Avoided by 400kV Development Plan
GWh
EC Low DemandScenario
2,500
Low Demand Growth
Medium Demand Growth
2,000
High Demand Growth
1,500
1,000
500
-
2005
2010
2015
2020
2025
2030
2035
2040
Figure 4-18: Graphs of unserved energy per market development scenario for the
Electricity Commission’s scenarios
As can be seen, the Electricity Commission scenarios reflect even less new
generation appearing in the upper North Island than the Transpower scenarios and
the same conclusion can also be drawn i.e. that large scale base-loaded generation
cannot be considered as a transmission alternative as it has already been considered
in the analysis.
5.3 Energy Efficiency Alternatives
Energy efficiency as an alternative to transmission is taken into account by
sensitising demand forecasts. Energy efficiency initiatives tend to lower demand
overall, and this is already captured in Transpower’s demand forecasting models
(see Part II). If energy efficiency initiatives are more economic than transmission, the
expected net market benefit for low demand growth would be negative.
5.4 Demand Side Management Alternatives
Demand-side management alternatives are initiatives that take place on the
distribution side of the power system. They are not otherwise captured in
Transpower’s analysis and together with generation proposals they have formed the
subject of a Request for Information that Transpower sought from the electricity
industry.
5.5 Request for Information document
Transpower’s approach to determining the alternatives to transmission that have a
reasonable likelihood of occurring, was to issue a Request for Information (RFI)
document, seeking information on potential alternatives to transmission from
interested parties.
The document was published in September 2004. A full copy of that document is
available as a supporting document to this proposal.
Part III – Analysis of Options for Meeting the Investment Need
55
In brief the RFI:
•
described the regulatory requirement for considering alternatives to
transmission
•
described the process to be followed
•
outlined the existing transmission system
•
listed the existing generation in the upper North Island
•
outlined Transpower’s demand forecasts for the upper North Island
•
described Transpower’s grid planning criteria
•
provided information on the energy shortfall and seasonality requirement
that alternatives to transmission would need to meet in order to defer
investment in transmission
•
listed the criteria that transmission alternative proposals would be
assessed against
5.5.1 Submissions received in reply to the RFI
A summary of the submissions received in reply to the RFI is included in the table
below. To maintain confidentiality requested by some proposers, the submissions
have been generalised. The table includes a list of the types of proposal received
and the potential peak MW reduction on load if the proposal were implemented.
Approximate
Alternatives to transmission
potential peak MW
reduction (*)
Energy efficiency alternatives Range of general demand reduction initiatives that promote more
efficient use of electricity.
150-300 MW
Peak Demand Management Programmes
Demand bidding & communication programmes to target peak
demand reductions.
150-250 MW
Generation alternatives
Peaking and base load plant.
150 MW
(*) as estimated by the submitters
Table 4-13: Summary of submission types received in reply to the RFI
5.5.2 Application of initial screening process
The submissions were initially evaluated using a set of screening criteria developed
by Transpower. These screening criteria supplanted the criteria outlined in the RFI
document and served to eliminate several of the submissions which would not be
useful as alternatives to transmission in practice.
The screening criteria require that, in order to be evaluated further, a transmission
alternative must:
•
result in peak MW load savings
•
have reasonably guaranteed peak MW load savings
•
defer the need for transmission investment by 12 months or more
Part III – Analysis of Options for Meeting the Investment Need
56
The basis for these criteria is discussed below.
5.5.2.1 Would the proposal result in peak demand savings
Transmission is planned and implemented in a way that it enables demand to be met
during peak load times. Any transmission alternative must therefore deliver a
reduction in the peak demand required to be delivered by the transmission system
during these critical peak load times.
For example, alternatives that offer general energy savings but do not reduce the
peak demand on the transmission system were not considered as viable
transmission alternatives as they do not provide the same peak loads in an area may
occur on a daily basis between 7:00-7:30 am and 6:30-7:00 pm. An alternative which
reduces load at say, midday, but which does not reduce the load during peak times,
would not defer the need for transmission and therefore is not considered further.
Some of the proposals are based on demand reductions at off-peak times and as
such they cannot be considered transmission alternatives in this case.
5.5.2.2 Are the peak demand savings reasonably guaranteed
One of Transpower’s primary planning concerns is ensuring the transmission network
will deliver a secure supply of electricity, in accordance with Transpower’s
transmission planning criteria, during times of peak demand.
In that regard, only those transmission alternative proposals where the forecast peak
MW load savings can be reasonably guaranteed, were considered further.
Peaking generation plant, is an example of a transmission alternative which would
meet this need. Presuming it is contracted as a transmission alternative, Transpower
would advise the generator when to run, hence (reliability of the generating plant
aside), Transpower can guarantee the peak MW load savings would be made.
Some of the transmission alternative proposals rely on demand response to price
signals, which may reduce demand at peak times, but may not, depending on the
preferences of the consumers concerned. On a particularly cold day, for instance,
consumers may decide to consume “normal” levels of energy, irrespective of the cost
and hence the peak MW load savings would not be realised. The peak MW load
savings are too uncertain to reply upon from a security of supply point of view and
therefore they cannot be considered alternatives to transmission.
5.5.2.3 Would the transmission alternative defer the need for transmission
investment by one year or more
In the context of a six year transmission project, only those proposals that provide a
substantial deferral of transmission plans can be considered as viable alternatives to
transmission. With the risks that are associated with the current project timetable,
only those proposals that defer the need for transmission investment by one year or
more were considered further.
Application of the screening criteria resulted in the following outcome:
Part III – Analysis of Options for Meeting the Investment Need
57
Transmission alternatives
Are there Are the
Defer
peak MW peak MW
transmission
savings
savings
for 12 months
certain
or more
Energy efficiency alternatives Range of general demand reduction
?
?
2
initiatives that promote more efficient use of
electricity.
Peak Demand Management Programmes Demand bidding & communication
? ?
?
programmes to target peak demand
reductions.
Generation alternatives
Plant targeted at generating at during peak 9
9
9
load times.
Table 4-14: Application of Screening Criteria to Alternatives to Transmission
Energy efficiency initiatives were ranked low due to the fact that the initiatives could
not provide reasonable certainty of providing the necessary demand reductions at
time of peak load which is required for transmission investment deferral. The
implementation path also is unclear and is reliant on consumers adopting certain
technology and then continuing to use that technology for the long run.
Peak demand management initiatives were considered more likely to deliver the
demand reductions at the time that they are required to defer transmission
investment. However the implementation of such a system is unclear in terms of the
quantity of benefits available and whether these would continue to be available
during peak load times year on year. Transpower has commissioned work from
independent consultants to investigate the feasibility and implementation strategy for
such a system.
Therefore only the generation plant designed to operate at peak load times met the
screening criteria and was considered further using cost/benefit analysis in Part IV of
this submission.
5.6 Alternatives to Transmission Summary
According to the market development scenarios developed both by Transpower and
the Electricity Commission, there is insufficient new generation emerging in the upper
North Island to meet the forecast demand growth. On the basis that these scenarios
capture the reasonable extent of generation possible in the region, additional large
scale base-loaded generation cannot be considered as a realistic transmission
alternative.
Transpower assessed the potential transmission alternatives not reflected in the
market development scenarios, using a RFI process. Of the alternatives offered
through the RFI process, only generation peaking plant is considered viable and
further analysis is undertaken on peaking plant, using cost/benefit analysis, in Part IV
of this submission.
Part III – Analysis of Options for Meeting the Investment Need
58
Appendix III-A – Environmental Analysis & Process
Each of the transmission options will require a new transmission line extending from
Whakamaru to Otahuhu, as well as substation investment at each termination
location. This will require resource consents and designating the length of the route
pursuant to the Resource Management Act 1991 (RMA). Potential adverse
environmental effects of such a project are varied and may include, amongst others:
•
Safety and health effects (associated with electric and magnetic fields)
•
Social effects (disruption to communities).
•
Property values (financial costs resulting from social effects – this issue is
considered separately)
•
Visual effects
•
Effects on tourism and recreational values
•
Impact on sites of ecological significance or heritage value
•
Effects on cultural values
•
Effects on existing infrastructure – including transmission lines and roads.
•
Impact on land use (including disruption to agricultural activities as a
result of the establishment of new structures).
Until a final centre-line of the preferred transmission route is known, it is not possible,
or appropriate to identify the full environmental effects of each transmission option.
Analysis of the preferred option is considered in detail during the Resource
Management Act process, it is not expected to be relitigated outside that framework.
Transpower has developed the Area, Corridor, Route and Easement (ACRE) process
which will be utilised to identify (through analysis) the final line easement location and
any other mitigation measures to best manage adverse environmental effects of a
transmission solution.
The model is designed to enable Transpower to secure designations and property
rights for any new-build grid augmentation in a robust framework that meets the
legislative requirements of the key statutes – the Resource Management Act (RMA),
the Electricity Act and the Public Works Act (PWA) while also incorporating best
environmental practice. The key stages of ACRE are noted below:
A
=
Identification of study ‘Area’ and environmental/social/engineering
constraints and opportunities analysis mapping
C = Identification and confirmation of alternative ‘Corridors’ (500m to 5
kilometre wide corridors) ranking and selection of preferred corridor
Ri = Selection and evaluation of alternative ‘Routes’ within the confirmed
corridor and public presentation (for consultation)
Rii = Route confirmation following consultation.
E =
Identification and confirmation of ‘Easement’ centre-line and designation
boundaries (including ongoing consultation)
D =
Documentation – preparation of full documentation and notices of
requirement and resource consent application.
S =
Statutory – lodgement of notices of requirement and resource consent
applications, Council hearings, Transpower decision, Environment Court
Part III – Analysis of Options for Meeting the Investment Need
59
appeal process, (if required), and mediation, leading to confirmation (or
otherwise of designation.
The model is generic and is readily adaptable to the various transmission options
(220, 330, 400 kV etc.).
Detailed environmental analysis of each of the Area, Corridor and Route stages for
the 400 kV option is available as separate reports. They provide the justification for
identification of the two route options currently being consulted on, and more latterly
the preferred interim route decision.
When deciding between transmission options, it is, however, possible to identify and
assess broader environmental parameters that make one transmission option more
preferable than another. For example, lower capacity lines will require greater
numbers of transmission lines to transfer electricity. Furthermore, options that are
able to utilise the location of existing transmission lines or substations within a similar
envelope of environmental effects20 (visual, acoustic, social, ecological etc.) are more
preferable than options which require a new ‘greenfield’ location.
Site specific impacts of the various transmission options can be evaluated, to a
limited extent, on the basis of average tower height. Tower height determines visual
impact and also provides a useful proxy for potential impacts on site-specific issues
identified above. Tower height is a function of compliance with electric and magnetic
field limits contained in ICNIRP guidelines. It will, therefore, also provide an indication
of the likely perceived health concerns of the transmission option.
In this report, for each transmission option, the environmental effects are considered
on the basis of potential visual effects and the likelihood of any additional lines within
the foreseeable future. This analysis is presented for comparative purposes only. It
merely attempts to outline the primary differences between each transmission option
to enable the extent to which mitigation will be required, and thus the potential for
securing environmental approvals and associated costs (both of mitigation, and any
further investigations). In so doing, it is noted that visual effects (and each of the
other issues previously identified) are subject to the environment within which they
are located and thus not absolute. It is not possible to draw any firm conclusions from
this analysis until RMA processes are resolved.
20 The options identified do not provide opportunity for this scenario and are not considered further.
Part III – Analysis of Options for Meeting the Investment Need
60
Appendix III-B North Island Tactical Transmission Upgrade
Project Summary
A number of tactical transmission upgrade projects are planned to be implemented in
the North Island before 2010. A summary of these projects is as follows:
Region
Grid Upgrade Project
Capacity
Description
Auckland
Increase the operating temperature 671/614
MVA
Reduces constraints on
and North of the Huntly - Otahuhu section of
Huntly Generation and
Isthmus
Otahuhu - Whakamaru C 220 kV
increase thermal capacity
line
into Auckland
Thermal upgrade of Otahuhu -
323/293
MVA Increases the thermal
Whakamaru A&B lines
capacity into Auckland
Thermal upgrade of 220 kV 492/469 MVA
Increase the capacity of
Otahuhu-Penrose 5&6 circuits
the existing 220 KV
Otahuhu-Penrose 5&6
circuits
Thermal upgrade of 220 kV 984/938 MVA
Increases the capacity of
Otahuhu-Henderson circuits
both existing 220 KV
Otahuhu-Henderson
circuit
Shunt capacitors at Penrose 2x50 Mvar
Increases the transfer limit
110 kV
until the Huntly E3P unit is
commissioned in 2007
Shunt capacitor at Hepburn Road 1x50 Mvar
Increases the transfer limit
110 kV
until the Huntly E3P unit is
commissioned in 2007
Wellington
Increase the operating temperature 335/307 MVA
Increase transfer south to
of the Bunnythorpe- Haywards
Haywards from 640/760
A&B 220 kV line
MVA to 920/960 MVA
Central
Increase the operating temperature 335/307 MVA
Increases the thermal limit
North Island of the Tokaanu - Whakamaru A&B
between the Central North
220 kV lines
Island and the bay of
Plenty region
Thermal upgrade of the Rangipo-
370/333 MVA
Increases the thermal limit
Wairakei 1
between the Central North
Island and the bay of
Plenty region
Thermal upgrade of the Wairakei-
448/421 MVA
Increases
the
Pohipi-Whakamaru 220 kV circuits
transmission capacity in
Wairakei ring
Thermal
upgrade
of
the
335/307 MVA
Increases thermal limit of
Bunnythorpe-Tokaanu 1&2
the Central North Island
core grid corridor
Part III – Analysis of Options for Meeting the Investment Need
61
