NORTH ISLAND GRID UPGRADE PROJECT
AMENDED PROPOSAL
APPLICATION FOR APPROVAL
20 OCTOBER 2006
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Contents
1
Introduction 9
1.1
Purpose of this project
9
1.2
Background to this document
9
1.3
Purpose of this document
9
1.4
References to Original Grid Upgrade Plan
9
2
Approval sought
11
2.1
The Amended North Island Grid Upgrade Proposal
11
2.2
Transpower’s Intended Approach to Project Management
12
2.3
Regulatory context, and structure, of this application for approval
12
2.4
Suggested process and timetable for a draft decision
13
3
Needs assessment
14
3.1
Load forecast
14
3.2
Reliability criteria and timing
15
4
Options considered
16
4.1
Options considered by Transpower in the 2005 Grid Upgrade Plan
16
4.2
Alternatives considered by the Electricity Commission
16
4.3
Developing transmission augmentation projects - technology
16
4.4
Transmission Augmentation Projects
17
4.4.1
Option 1: 220 kV into Pakuranga and Otahuhu.
17
4.4.2
Option 2: 400 kV into the South Auckland urban boundary, 220 kV into
Pakuranga and Otahuhu
18
4.4.3
Option 3: Augmentation of existing 220 kV assets.
18
4.4.4
Option 4: Augmentation of existing 220 kV assets using high temperature
conductor
19
4.4.5
Option 5: 400 kV into Otahuhu.
20
4.4.6
Option 6: 220 kV into Otahuhu.
20
4.4.7
Option 7: 400 kV into Pakuranga and Otahuhu.
20
4.4.8
Option 8: 400 kV into the vicinity of the South Auckland urban boundary, 220
kV into Pakuranga and Otahuhu – early conversion to 400 kV.
21
4.4.9
Common augmentations
21
4.5
Non-transmission alternatives
21
4.6
Limiting the options
21
4.6.1
Diversity 21
4.6.2
Capital Cost
23
4.7
Non-qualifying alternatives
23
4.7.1
HVDC alternatives
23
4.7.2
Option 4: Duplexing of Whakamaru-Otahuhu A&B lines with high temperature
conductor
25
4.8
Electric and magnetic fields: transmission design issues for the options
25
4.9
Alternatives for further analysis
26
4.9.1
Option 1: 220 kV into Pakuranga and Otahuhu
26
4.9.2
Option 2: 220 - 400 kV staged to Pakuranga:
27
4.9.3
Option 3: Duplexing of Whakamaru-Otahuhu A&B lines
27
4.10 Selecting the Proposed Investment
27
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
5
Transpower’s Amended Proposal
29
5.1
Proposal description and timetable
29
5.2
Proposal costs
33
5.2.1
Method for Estimating 90% Cost Limit
35
5.2.2
Assumptions for Key Variables
36
5.2.3
Comparison of Costs with September 2005 GUP
37
5.3
Proposal is a reliability investment
38
5.4
Proposal is an amendment
39
6
The Amended Proposal meets the requirements of the Rules
41
6.1
Rule 13.4.1.1: The Amended Proposal demonstrates GEIP in meeting the
GRS
41
6.1.1
The GRS
41
6.1.2
Definition of “Good Electricity Industry Practice”
44
6.1.3
GEIP in meeting the GRS
45
6.2
Rule 13.4.1.2: The Original GUP complies with Rule processes
46
6.3
Rule 13.4.1.3: The Amended Proposal satisfies the Grid Investment Test
48
6.3.1
Discussion on Options 1 & 2: new line WKM-PAK
51
6.3.2
Discussion of the potential ranges of outcomes
51
6.3.3
Other non-quantified benefits favouring the proposal
53
6.3.4
Discussion on Option 3: Duplex WKM-OTA A and B
56
6.3.5
Discussion on Option 4: Duplex WKM-OTA A and B with HTC
58
6.3.6
Comparison with non-transmission alternatives
60
6.3.7
Impact of the draft GPS
61
6.3.8
Conclusion of the GIT analysis
62
7
The Amended Proposal is appropriately sequenced and timed
63
7.1
Probabilistic method of determining project timing
63
7.2
Deterministic method of determining project timing
63
7.3
Grid Development Projects
63
7.4
Short-term projects
64
7.4.1
Arapuni-Pakuranga 110 kV line
65
7.5
Appropriate timing
65
7.5.1
Probabilistic approach - Transpower
66
7.5.2
Probabilistic approach – Electricity Commission
66
7.5.3
Deterministic analysis
66
7.5.4
Conclusion on timing
67
7.6
Accounting for delivery risk
67
7.7
Timing of the Proposal
69
8
The Amended Proposal is consistent with wider policy objectives
70
8.1
The purpose of Part F
70
8.2
The GPS
71
8.3
The Commission’s objectives
83
9
Recommendation 84
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Appendix A
Glossary of Terms
85
Appendix B
Cross Reference with September 2005 GUP
88
Appendix C
Cost breakdowns of alternative projects
93
Appendix D
Short Term Augmentation Projects
101
Appendix E
Assessment of the value of deferring investments
104
Attachments
Attachment A
Diversity Into the Upper North Island
Attachment B
Treatment of the Arapuni – Pakuranga Line
Attachment C
Project Delivery Risk
Attachment D
Technical Assessment of Modified Options
Attachment E
Economic Assessment of the North Island Grid Upgrade Project
Attachment F
Costing Report
Attachment G
High Temperature Conductor Report
Attachment H1
Timing of Auckland Grid Supply Upgrade
Attachment H2
Pre-Augmentation EUE Assessment (ROAM Report)
Attachment I
Otahuhu – Whakamaru A & B Duplexing Report
Attachment J
Assumptions List from the Independent Working Party
Attachment K
Economic Analysis of Non-Transmission Alternatives
Attachment L
Discount Rate for the Grid Investment Test Report
Attachment M
Assessment of the Value of Unserved Energy
Attachment N
Foreign Direct Investment Effects
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Executive Summary
This document represents Transpower’s Amended Proposal for the North Island Grid
Upgrade Project, and updates (and replaces where defined), Transpower’s original
proposal that was submitted to the Electricity Commission as part of a full Grid
Upgrade Plan in September 2005.
Amended Proposal - Works
The following works make up the Amended Proposal for which Transpower is now
seeking approval:
The following works make up Transpower’s Amended North Island Grid Upgrade
Proposal (the Amended Proposal):
• Procure, construct, commission and operate a 220 kV switching station in the
vicinity of Drury and upgrade the 220kV Otahuhu – Whakamaru C line by
2010.
• Procure, construct, commission and operate 350 MVAr of new static reactive
plant at Otahuhu substation by 2010.
• Procure, construct, commission and operate a new double-circuit, steel lattice
tower, overhead transmission line of approximately 190km from a new
substation near the existing Whakamaru substation to a new transition station
in the vicinity of the South Auckland urban boundary, that is capable of:
o 220 kV operation
o future 400 kV operation of around 2700 MVA, subject to later Commission
approval of and Transpower commissioning of 220
kV-400
kV
transformers and associated switchyards near the existing Whakamaru
substation and in the vicinity of the South Auckland urban boundary.
• Procure, construct, commission and operate two underground cables from the
new transition station in the vicinity of the South Auckland urban boundary to
Pakuranga substation that:
o are capable of 220 kV operation; and
o have a continuous rating of around 660 MVA per set of cables
• Procure, construct, commission and operate the necessary substation /
transition station facilities near the existing Whakamaru substation (Air
Insulated Switchgear [AIS]), a transition station in the vicinity of the South
Auckland urban boundary (AIS), and Pakuranga substation (Gas Insulated
Switchgear [GIS]).
• Plan the works, including the acquisition of designations, consents and
easements to allow for future upgrade to 400 kV operation through future
addition of:
o new 400/220 kV transformers and associated works near the existing
Whakamaru substation to interconnect with the existing 220 kV system;
o a new switchyard in the vicinity of the transition station with new
400/220 kV transformers and associated works; and
o new overhead lines or underground cables to connect the new switchyard
with the new transition station.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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o new 220 kV underground cables to Otahuhu substation.
o extensions to the Otahuhu switchyard(s)
• Carry out the works necessary to convert and connect the existing 110 kV
Otahuhu-Pakuranga line to 220 kV operation, for which it is already designed
and consented;
• Dismantle the existing 110 kV Arapuni to Pakuranga transmission line
• Obtain designations, easements, resource consents and property purchases
necessary for all the above works.
• Plan for a commissioning date for the major projects above of 2011 to
prudently allow for potential delays due to delivery, designation, consenting
and easement risks.
Amended Proposal – Cost
Transpower is seeking Electricity Commission approval for costs incurred by
Transpower in the implementation of the Amended Proposal in accordance with the
90% limit of project costs in 2011 dollars, estimated at $824 million. The table below
provides a breakdown of that cost:
Amended Project
Cost Category
$ 2011 (million)
Investigations
27
Property
116
Environmental
8
Transmission Works:
- Lines
400 kV line
203
Up-rate OTA-WKM C
4
OTA-PAK 110kV Circuits
1*
Drury
2
- Substations
Otahuhu
12
Whakamaru
13
Pakuranga
55
Drury
16
Static Compensation
8
- Cable
110
Dismantling
5
Project Management
34
Subtotal
614
Contingency
105
Exchange Rate
25
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Interest During Construction
80
TOTAL
824
*This cost will increase by between $7M and $10M if the Otahuhu diversity project does not proceed.
Rule Requirements
Transpower considers the Amended Proposal as described above meets the
requirements of the Rules in that:
The Amended Proposal reflects good electricity industry practice in meeting
grid reliability standards.
Specifically, the proposal and approach is consistent with international
practice as being a prudent investment given the size, nature and importance
of the Auckland load.
The Amended Proposal complies with the Rule processes
Transpower considers that the Amended Proposal follows the processes set
out in Section III, Part F of the Electricity Governance Rules.
The Amended Proposal satisfies the Grid Investment Test
Under the Grid Investment Test, the Amended Proposal has a net market
cost that is $10 million lower than the closest other option (220 kV into
Pakuranga). Under sensitivity analysis across a wide range of assumptions,
the Amended Proposal was better than other options in a significant majority.
Timing
Two methods for determining the actual timing of the proposed project – probabilistic
and deterministic. The outcome from the timing analysis is as below:
Requirement
Method
Date
Probabilistic (EC model):
2013
(combining the Grid Reliability Standards and Grid Investment Test)
Deterministic:
2013
(using an n-g-1 security criteria and a prudent forecast)
When delivery risk is included, the timing for the project is as below:
Project Delivery: (allowing for delivery risk)
2011
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Recommendation
It is recommended that the Commission approve the Amended Proposal on the
grounds that it:
• complies with the Rules;
• meets the GRS;
• passes the GIT; and
• is consistent with GEIP.
Further, it is the project that is most aligned with the draft changes proposed to the
GPS, particularly with respect to an emphasis on renewable generation, provision of
diversity of supply to Auckland and minimisation of the number of corridors required
for transmission.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
1 Introduction
1.1 Purpose of this project
1
The purpose of the North Island Grid Upgrade project is to maintain reliable bulk
electricity supply for the upper North Island.
2
The purpose of this document is to obtain approval from the Electricity
Commission for delivery of this upgrade, and for the recovery of the cost of doing
so.
1.2 Background to this document
3
On 30 September 2005 Transpower submitted a Grid Upgrade Plan (the “Original
GUP”) to the Electricity Commission (the “Commission”), which included a
proposal for a “reliability investment” to construct a new 400 kV double circuit line
between Whakamaru near Tokoroa, and Otahuhu in South Auckland (the
“Original Proposal”).
4
The Commission commenced a consultation process on the Original Proposal on
27 April 2006 and also commenced consultation on its draft decision to decline
approval.
5
On 31 May 2006 Transpower informed the Commission of its intention to amend
the Original Proposal. Transpower also asked the Commission to suspend its
consideration of the Original Proposal and the Commission agreed to such
suspension.
1.3 Purpose of this document
6
This document is Transpower’s submission to amend the Original Proposal
contained in the Original GUP. The amendment relates solely to the Original
Proposal and, except as set out in this submission, the Original GUP remains
otherwise unchanged.
7
Transpower notes that the approval processes for the other investments
contained in the original GUP are currently suspended, with the agreement of the
Commission. Transpower confirms that it may submit amendments to those other
investments in the Original GUP at appropriate times in the future.
8
Transpower suggests the timetable and process for consultation as outlined in
Section 2.4 in relation to this amendment submission, for consideration by the
Commission. Transpower also suggests that the consultation process which was
suspended on 31 May 2006 be reinstated and continued.
9
Transpower notes that the Commission has withdrawn its draft decision to decline
approval of the application for the Original Proposal as proposed in the Original
GUP.
1.4 References to Original Grid Upgrade Plan
10 This proposal is an amendment to the Original GUP of September 2005. A full
cross reference between the Original GUP and this Amended Proposal is
provided in Appendix B, and is summarised below:
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Volume of
Amended by
Original
Section
this proposal
GUP
Vol I
Executive summary
Yes
Asset Management Plan
No
Contracted Investments
No
Vol II
400 kV Grid Upgrade Plan
Yes
Vol III
HVDC Inter Island Link
No
Vol IV
Grid Development Proposals
No
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
2 Approval
sought
11 Transpower seeks approval from the Commission to recover the actual costs
incurred in delivering the project through the transmission pricing methodology
following commissioning of the project. Transpower will not exceed the amount
approved for the project without further approval from the Commission. Costs are
to include the accrued interest charged on works under construction.
2.1 The Amended North Island Grid Upgrade Proposal
12 The following works make up Transpower’s Amended North Island Grid Upgrade
Proposal (the Amended Proposal):
• Procure, construct, commission and operate a 220 kV switching station in the vicinity
of Drury and upgrade the 220kV Otahuhu – Whakamaru C line by 2010.
• Procure, construct, commission and operate 350 MVAr of new static reactive plant at
Otahuhu substation by 2010.
• Procure, construct, commission and operate a new double-circuit, steel lattice tower,
overhead transmission line of approximately 190km from a new substation near the
existing Whakamaru substation to a new transition station in the vicinity of the South
Auckland urban boundary, that is capable of:
o 220 kV operation
o future 400 kV operation of around 2700 MVA, subject to later Commission
approval of and Transpower commissioning of 220 kV-400 kV transformers and
associated switchyards near the existing Whakamaru substation and in the
vicinity of the South Auckland urban boundary.
• Procure, construct, commission and operate two underground cables from the new
transition station in the vicinity of the South Auckland urban boundary to Pakuranga
substation that:
o are capable of 220 kV operation; and
o have a continuous rating of around 660 MVA per set of cables
• Procure, construct, commission and operate the necessary substation / transition
station facilities near the existing Whakamaru substation (Air Insulated Switchgear
[AIS]), a transition station in the vicinity of the South Auckland urban boundary (AIS),
and Pakuranga substation (Gas Insulated Switchgear [GIS]).
• Plan the works, including the acquisition of designations, consents and easements
to allow for future upgrade to 400 kV operation through future addition of:
o new 400/220 kV transformers and associated works near the existing
Whakamaru substation to interconnect with the existing 220 kV system;
o a new switchyard in the vicinity of the transition station with new 400/220 kV
transformers and associated works; and
o new overhead lines or underground cables to connect the new switchyard with
the new transition station.
o new 220 kV underground cables to Otahuhu substation.
o extensions to the Otahuhu switchyard(s)
• Carry out the works necessary to convert and connect the existing 110 kV Otahuhu-
Pakuranga line to 220 kV operation, for which it is already designed and consented;
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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• Dismantle the existing 110 kV Arapuni to Pakuranga transmission line
• Obtain designations, easements, resource consents and property purchases
necessary for all the above works.
• Plan for a commissioning date for the major projects above of 2011 to prudently
allow for potential delays due to delivery, designation, consenting and easement
risks.
2.2 Transpower’s Intended Approach to Project Management
13 On approval of the package listed in paragraph 12, Transpower intends to:
• Deliver the package listed in paragraph 12.
• Conduct for the Transpower Board independent periodic audits of its project
management, procurement and commercial processes to demonstrate that
cost controls are in place, with a demonstration of the process of business
improvement in response to any issues identified.
• Report periodically to the Transpower Board on progress against both
expected costs and cost with contingencies, and reasons for any divergence
(e.g. foreign exchange), allowing for indexed escalation or deflation of linked
costs.
• Transpower acknowledges that to manage the project risk it is essential that a
high degree of quality assurance is applied in planning, design, manufacture,
commissioning, testing and maintenance activities in accordance with good
electricity industry practice.
14 Transpower recognises that, following approval, if it transpires that it cannot meet
some aspect of the approved project above, such as the cost ceiling, it has the
option to seek the Commission’s agreement to an amendment under Rule 17.2.
2.3 Regulatory context, and structure, of this application for approval
15 This is an amendment to an application for approval of a reliability investment
under Part F of the EGRs. Section 1 introduces the application, while section 2
specifies what Transpower is seeking Commission approval for. Section 3 sets
out the need for investment while the options assessed to meet that need and
Transpower’s Amended Proposal are covered in sections 4 and 5 respectively.
16 Transpower acknowledges that in order to be approved, the proposed reliability
investment must satisfy the following criteria:
13.4.1.1
“reflects good electricity industry practice in meeting grid
reliability standards”; and
13.4.1.2
“complies with the processes set out in these Rules”; and
13.4.1.3
“meets the requirements of the Grid Investment Test”.
17 The justifications of the Amended Proposal against these three criteria,
respectively, are described in section 6.
18 This is followed by section 7 that addresses the timing of the investment.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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19 In section 8 Transpower sets out a number of factors that it considers to be
relevant to the Commission’s assessment of the proposal.
20 Finally, section 9 sets out Transpower’s recommendations to the Commission.
2.4 Suggested process and timetable for a draft decision
21 In order to make full use of the work already done by interested parties in making
relevant submissions to date on the Original Proposal, Transpower requests that
the Commission makes it clear to interested parties that they should indicate the
extent to which of their earlier submissions or comments are to apply to the
consultation and consideration by the Commission on the Amended Proposal.
Transpower is of the view this will help make the consultation process more
timely. If the proposal is to be built in time to minimise negative impact on grid
security and reliability in the upper North Island, a draft decision is desired by the
end of 2006. If a draft decision is not reached by Christmas 2006, this may have
negative implications for the lodging of a Notice of Requirement and acquisition of
easements by the deadline required by the project implementation timetable,
which in turn will have knock on effects to the project management of the
Amended Proposal, which may impact on Transpower’s ability to implement the
project in time to maintain reliability into the upper North Island.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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3
Needs assessment
22 The needs analysis concludes that there is a risk of some electricity demand not
being supplied to the upper North Island region at times of peak loading from
2013 and that new investment is required to maintain security of supply into that
region. This date assumes that projects already approved by the Commission are
commissioned by their target dates or, alternatively, no later than 2010. In
particular, these projects include:
•
Establishment of Ohinewai substation (Huntly East);
•
Thermal upgrade of the 220 kV Otahuhu-Whakamaru A and B lines;
•
Bombay bus split ; and
•
The reactive power investments in the Upper North Island as approved by the
Commission.
23 The September 2005 Grid Upgrade Plan, Volume 2, Part 2, “Establishing the
Need for New Investment” provided details on how the need for the new
investment is assessed.
24 The technical analysis of transmission options was carried out using the same
assumptions as in the September 2005 GUP, with the exception of the items
listed below:
Item
September 2005 GUP
Amended Proposal
Load
2005 SoO with medium load
2005 SoO with a ‘prudent’ high
forecast
growth scenario
demand forecast
Security
n-1 with allowance for reduced
Two assessments are made:
criteria
generation
o
Grid Reliability Standard as
applied in the draft decision
on the 400 kV project; and
o
n-1 with allowance for the
Otahuhu CCGT to be out of
service
Table 3.1: Comparison of assessment assumptions
3.1 Load
forecast
25 The Commission provided the load forecast used for this Amended Proposal. The
load data is based on the 2005 Statement of Opportunities. This is the same as
the September 2005 GUP but with a higher growth scenario. The growth scenario
used was changed for the following reasons:
• experience gained from higher than predicted loads during winter 2006;
• alignment with good electricity industry practice (i.e. use of a high or ‘prudent’
rather than a medium forecast ); and
• improvements in forecasting technology and methods.
26 The impact of these changes is that the load forecast used for the Amended
Proposal is higher than used for the September 2005 GUP, as illustrated below:
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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6,000
5,000
4,000
W
M 3,000
ak
Pe
2,000
1,000
2005 SoO with prudent high demand
2005 SoO medium load forecast
-
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043
Year
Figure 3-1: Comparison of load forecasts used for the Original and Amended Proposals
3.2 Reliability criteria and timing
27 The September 2005 GUP used a reliability criterion of n-1 with “an assessment
of the likely level of actual generation that can be reasonably and prudently
assumed to be available”.
28 Two security criteria are used in this assessment:
• A probabilistic assessment using the Grid Reliability Standards and the Grid
Investment Test together to determine the required timing of projects; and
• A deterministic criterion that, in Transpower’s view, is consistent with the Grid
Reliability Standards in that it makes the ‘reasonable’ allowance that the
largest generator in the Auckland area may not be available at the same time
peak demand occurs.
29 The probabilistic assessment is based on the methods outlined in the draft
determination and calculates the required date for the project by assessing and
balancing the cost of expected unserved energy (EUE) against the net cost of the
proposed investment.
30 The deterministic security level applied to Auckland for the technical analysis in
the Amended Proposal is n-g-1 where g is the Otahuhu CCGT generator and n is
the worst single credible transmission line or generator contingency.
31 Both methods are used because Transpower, when it was preparing this
application, had concerns that the probabilistic approach would not deliver an
investment timing that was commensurate with the more widely used and
historically proven deterministic standard.
32 Transpower agreed to provide both sets of results to inform a comparison of the
outcomes. Transpower agrees with the Commission’s conclusion in its draft
decision that an outcome that meets n-g-1 is appropriate for a critical load centre
like Auckland.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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4 Options
considered
4.1 Options considered by Transpower in the 2005 Grid Upgrade Plan
33 For the Original Proposal submitted as part of the Original GUP in September
2005, Transpower undertook an analysis of a number of transmission options and
alternatives to transmission (including generation and demand side management)
to meet the need for investment. These options included:
• 330 kV development
• 500 kV development
• Classic HVDC development
• HVDC
Light
development
• Under-grounding (either HVDC or HVAC)
• Peaking generation plant
34 The analysis carried out for the Original Proposal regarding these options
concluded that they did not pass the assessment criteria. This conclusion
remains unchanged and therefore these options (other than classic HVDC
development and peaking generation plant) are not analysed further in this
proposal.
4.2 Alternatives considered by the Electricity Commission
35 As part of their assessment of the 2005 Grid Upgrade Plan including the North
Island 400 kV Upgrade Project, the Commission consulted widely on alternatives
to the project.
36 The Commission narrowed the projects down to a short list and ultimately a set of
alternatives to which the North Island 400 kV Upgrade Project was compared.
These alternatives comprised 220 kV, 400 kV and HVDC projects1.
37 This Amended Proposal builds off the analytical results obtained in the
Commission’s draft determination.
38 In their draft determination, the most cost effective alternative was the 220 kV
project, with the HVDC and 400 kV (in 2010) being more costly.
39 Transpower, in considering alternatives for the Amended Proposal, has used the
results of the draft decision and selected their best alternative – the 220 kV
project – as the reference case for the economic analysis.
40 On the basis that both Transpower and the Commission analysis showed HVDC
was not as cost effective, an HVDC alternative has not been considered in the
economic analysis for the Amended Proposal.
41 Further discussion on the HVDC options is provided in Section 4.7.
4.3 Developing transmission augmentation projects - technology
42 The development of possible projects that would meet the demand is challenging
because of the number of potential options that exist using various permutations
and combinations of technologies, routes and forecasts.
1 http://www.electricitycommission.govt.nz/opdev/transmis/400kv/400kValternatives
October 2006
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43 The choice of technology is of interest because, over the period of the analysis, it
is likely that some new or refined technologies will emerge. In addition, the long
life of the assets involved, and the staging of developments associated with those
assets, means that there will be a number of decision points through the study
period.
44 While there may be a high level of confidence that the first investment is a sound
decision, technological and other change introduces uncertainties for all future
decision points.
45 It is possible that at each of these decision points, the decision makers of the day
could be faced with compelling reasons to change technologies or to depart from
what today’s decision makers would regard as a ‘normal course of action’.
46 Unless the analysis period is short – say 10 years or less – most if not all possible
projects to meet the need will be subject to the same uncertainties.
47 The approach taken by Transpower, and the Commission in their draft decision,
is to select a project option based on a known technology and for future stages
and development to be consistent with this technology. For example, choosing a
220 kV line of certain design characteristics would be followed by a similar
development when required.
48 Changing technology at a decision point has been avoided in the analysis on the
assumption that relative rankings of technologies do not change over time. For
example, if 220 kV technology is less costly than HVDC for a comparative
capacity, it is assumed this will remain true over the study period unless there is a
compelling reason to believe otherwise.
49 The adoption of project staging delivers future opportunities to optimise
investments to take account of actual outcomes and technological change.
Staging thus provides opportunities to cap project downside while enabling
upside.
50 The development of transmission augmentation projects has thus focused on
providing:
• technology consistency through the study period; and
• staging to cap downside risks and provide opportunities to optimise
future developments.
51 This approach in defining possible projects is based on using the best available
information at the time of decision making and delivering a ‘low regret’ outcome.
4.4 Transmission Augmentation Projects
52 For the Amended Proposal, a total of eight transmission augmentation projects
were analysed in terms of their technical feasibility. All projects share a common
set of augmentations and are described in broad terms below:
4.4.1
Option 1: 220 kV into Pakuranga and Otahuhu.
53 This project involves:
•
Building a new
220 kV double circuit transmission line between Whakamaru
and the South Auckland urban boundary with 220 kV underground cables
from the South Auckland urban boundary to Pakuranga;
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•
Building additional 220 kV cables from the South Auckland urban boundary to
Otahuhu when required;
•
Installing series compensation on the transmission line, when required, to
increase the transfer capacity to the upper North Island; and
•
Building an additional 220 kV double circuit transmission line between
Whakamaru and Otahuhu when the transfer capacity to the upper North
Island is exhausted.
54 The line design chosen for any new 220 kV line options was intended to meet the
intent of the (draft) GPS requirement 88E for fewer corridors of high capacity. The
heaviest conductor in use on 220 kV lines at present is Chukar and the line was
optimised to give the greatest available capacity with this conductor for the lowest
practicable implementation cost.
55 The resulting tower heights are up to 58m. Lower tower heights are possible but
with a significant increase in the number of towers and therefore cost.
56 Transpower believes if the proposed project can be shown to have greater
benefits than this optimised 220 kV line, it will also be superior to a sub-optimal
and higher cost line.
4.4.2
Option 2: 400 kV into the South Auckland urban boundary, 220 kV
into Pakuranga and Otahuhu
57 This project involves:
•
Building a 400 kV double circuit transmission line between Whakamaru and
the South Auckland urban boundary then 220 kV underground cables from
the South Auckland urban boundary to Pakuranga;
•
Building additional 220 kV cables from the South Auckland urban boundary to
Otahuhu when required; and
•
The transmission line would initially operate at 220 kV with series
compensation to increase the transfer capacity to the upper North Island first
and then convert to 400 kV operation when required.
58 The 400 kV line design is a result of optimisation and the requirements to meet
technical guidelines relating to audible noise, electric and magnetic field
strengths. Audible noise was a limiting factor and required the adoption of a
triplex conductor configuration.
59 The conductor configuration provided a significant increase in the thermal
capacity of the line, increasing from 1600 MVA of the original proposal to 2700
MVA for the current design.
60 The provision of a 400 kV substation in the South Auckland urban boundary
region allows the full capacity of this line to be utilised in the proposal as 220 kV
cables can be added as required to match the line capacity.
4.4.3
Option 3: Augmentation of existing 220 kV assets.
61 This project involves:
• Duplexing the 220 kV Otahuhu – Whakamaru A & B single circuit lines;
and
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• Re-terminating the Otahuhu-Whakamaru A and B transmission lines to
Pakuranga from a point near the South Auckland urban boundary using
220 kV underground cables2.
• Building additional 220 kV double circuit transmission lines between
Whakamaru and Otahuhu when the transfer capacity to the upper North
Island is exhausted.
62 The degree of strengthening required was determined using a factor representing
the criticality of the line. Other factors affecting the degree of strengthening
required were the age (40-50 years old) and design of these lines.
63 In this case, Transpower has used the same factors it would apply to any such
significant 220kV (or indeed, 400kV) line. It is assumed the tower members are
all in place and structurally competent when calculating the strengthening
requirements.
64 Strengthening the towers to any lower level would imply some agreed programme
to retire the towers and line before a typical line life of 40 (additional) years. This
is in line with the (draft) GPS requirement to provide solutions that are consistent
with good electricity industry practice (clause 87C) and provide long-term
confidence in the reliability of supplies (clause 87 G).
65 A lower level of structural strength would create uncertainty about both the life of
the line and its ability to withstand more onerous weather conditions, resulting in
departures from good industry practice and provision of short-term rather than
long-term solutions.
66 Transpower considered a variant to this option whereby the existing assets from
the transition station would be utilised, saving the cost of one set of cables. This
option would require additional space to effect the connection between one of the
duplexed circuits and the two remaining sections of simplex construction
extending into Otahuhu.
67 The first suitable location for this transition station would be at Redoubt Road,
approximately 1 km further south than the currently proposed transition station.
68 Transpower considered there would be two primary effects of this variant:
• Reduction in cost gained by removing one cable, which would be offset
by the additional costs of between $5M and $8M for the increased
length of cable; and
• A reduction in diversity as only one cable, representing approximately
660 MVA of capacity, would terminate at Pakuranga.
69 Given the weight attributed in the (draft) GPS to the provision of diversity,
Transpower did not consider this variant further.
4.4.4
Option 4: Augmentation of existing 220 kV assets using high
temperature conductor
70 This project is a variant on Option 3 and involves
• replacing the conventional aluminium steel core conductor (ASCR) with
high-temperature conductor (HTC) on the Otahuhu – Whakamaru A, B
and C lines. This would permit higher transfer capacities over existing
assets; and
2 The line section from Otahuhu to the South Auckland urban boundary would not be
duplexed and would be disconnected but will remain in place.
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• building an additional 220 kV double circuit transmission line between
Whakamaru and Otahuhu when the transfer capacity to the upper North
Island is exhausted.
4.4.5
Option 5: 400 kV into Otahuhu.
71 This project involves:
•
Building a new 400 kV double circuit transmission line between Whakamaru
and the South Auckland urban boundary and 400 kV underground cables
from the South Auckland urban boundary to Otahuhu.
•
The transmission line would initially operate at 220 kV with sub options as
follows:
Sub option 5.1: Converting to 400 kV operation first and then installing
series compensation to increase the transfer capacity into Upper North
Island when required; or
Sub option 5.2: Installing series compensation to increase the transfer
capacity to the upper North Island first and then converting to 400 kV
operation when required.
4.4.6
Option 6: 220 kV into Otahuhu.
72 This project involves:
•
Building a new 220 kV double circuit transmission line between Whakamaru
and the South Auckland urban boundary with 220 kV underground cables
from the South Auckland urban boundary to Otahuhu.
•
Installing series compensation on the transmission line, when required, to
increase the transfer capacity to the upper North Island.
•
Building an additional 220 kV double circuit transmission line between
Whakamaru and Otahuhu when the transfer capacity to the upper North
Island is exhausted.
4.4.7
Option 7: 400 kV into Pakuranga and Otahuhu.
73 This project involves:
• Building a 400 kV double circuit transmission line between Whakamaru and
the South Auckland urban boundary and 400 kV underground cables from the
South Auckland urban boundary to Pakuranga.
• Building additional 400 kV cables from the South Auckland urban boundary to
Otahuhu when required.
• The transmission line would initially operate at 220 kV with sub options as
follows:
Sub option 7.1: Converting to 400 kV operation first and then installing
series compensation to increase the transfer capacity into the upper
North Island when required; or
Sub option 7.2: Installing series compensation to increase the transfer
capacity to the upper North Island first and then converting to 400 kV
operation when required.
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4.4.8
Option 8: 400 kV into the vicinity of the South Auckland urban
boundary, 220 kV into Pakuranga and Otahuhu – early conversion
to 400 kV.
74 This project involves:
•
Building a 400 kV double circuit transmission line between Whakamaru and
the South Auckland urban boundary with 220 kV underground cables from the
South Auckland urban boundary to Pakuranga.
•
Building additional 220 kV cables from the South Auckland urban boundary to
Otahuhu when required.
•
The transmission line would initially operate at 220 kV and convert to 400 kV
operation early-on and then install series compensation when required to
increase the transfer capacity into the Upper North Island.
4.4.9 Common
augmentations
75 A number of augmentations are common to all of the projects. These common
projects are drawn from the Annual Planning Report 2006 (Sections 5 to 13). The
common projects are listed in the technical report (Attachment D).
4.5 Non-transmission
alternatives
76 Three non-transmission alternatives were identified and analysed:
•
155 MW OCGT, 3 shaft, peak load option;
•
240 MW CCGT, single shaft, base load option;
•
380 MW coal fired steam turbine, single shaft, base load option.
77 Transpower specified the capital, fuel and other assumptions used in the
analysis. The approach was to bias assumptions towards the generation option to
ensure any close options would be identified.
4.6 Limiting the options
78 An assessment of the projects was carried out in order to limit the number of
projects against which the Grid Investment Test (GIT) would be applied, in
accordance with schedule F4, item 11 of the Electricity Governance Rules
(EGR’s).
79 The criteria used to assess and limit the number of projects were:
• Diversity;
and
• Capital cost.
4.6.1 Diversity
80 Following the 12 June 2006 event in which approximately half of the Auckland
load was lost due to earth-wire conductors dropping across busbars, concerns
were raised about the dependence of the Auckland load on a single substation.
81 A review of the Auckland supplies indicated a lack of diversity in relation to:
• Substation
switchyards;
• Substation locations; and
• Transmission line corridors.
82 Options to address the lack of diversity in relation to each of the three points
above were documented in the aftermath of the 12 June 2006 event. A more
detailed discussion on the benefits of diversity is provided in Attachment A.
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83 The draft GPS has an objective to provide adequate alternative supply routes to
larger load centres and to be resilient against low probability but high impact
events (Clause 80).
84 Transpower decided to terminate options at Pakuranga but to assess the cost
differential of providing this diversity against the Original Proposal of initially
terminating the options at Otahuhu.
New line terminates at
New line terminates at
Item
Pakuranga
Otahuhu
($2006 million)
($2006 million)
Lines
215
215
Cables
104
104
Substations
102
53
Property
96
96
Consenting
7
7
Investigation
23
23
Project management
34
34
Dismantling
5
4
Total
586
535
Table 4-1. Capital cost comparison of terminating the new line at
Pakuranga and Otahuhu
85 Table 4-1 shows that the proposal, including a new line terminating at Pakuranga
in 2011, has a total substation capital cost of approximately $102 million. This
provides improved diversity of supply for Auckland consumers by reducing
reliance on the Otahuhu substation.
86 Alternatively, the new line could terminate at Otahuhu in 2011, which would
reduce the total substation capital cost to approximately $53 million, but without
any improvement in diversity.
87 Good Electricity Industry Practice (GEIP) requires reducing reliance on Otahuhu
substation in the future and this is reflected in the long term development plans
for Auckland, which show that Pakuranga substation would be developed by
2021 under all scenarios.
88 The cost of providing diversity of supply now, by terminating the new line at
Pakuranga instead of Otahuhu is $15 million. This is the difference in present
value terms between spending $102 million in 2011, or spending $53 million in
2011 followed by a further $49 million in 2021.
89 It should also be noted that Pakuranga substation may be upgraded to 220 kV
sooner than 2021, regardless of where the new line is terminated. This is due to
the way in which Penrose substation may be reinforced as part of the North
Auckland and Northland project.
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90 One of the possible options identified in the recent North Auckland and Northland
request for information (RFI) for reinforcing supplies into Penrose is to go via
Pakuranga at 220 kV. The estimated cost for this option is the lowest of the five
possibilities presented in the RFI.
91 If this lowest cost option were to be selected then Pakuranga would have to
convert to 220 kV by around 2013. Under this scenario, the cost of diversity that
could be attributed to the North Island Grid Upgrade project is the cost of bringing
the Pakuranga substation conversion works forward by two years, which is
approximately $7m.
92 Based on the above analysis, Transpower believes that terminating future options
at Pakuranga rather than Otahuhu is sensible, prudent and consistent with the
(draft) GPS (Clause 80). Therefore options 5.1, 5.2 and 6 should be discarded.
4.6.2 Capital
Cost
93 Option 7.1 and option 7.2 (400kV into Pakuranga and Otahuhu) although
technically feasible, are more costly due to their requirement for two 220/400 kV
substations in Auckland, one each at Otahuhu and Pakuranga.
94 The capital cost of option 8 (early conversion to 400kV) is higher than for option 2
due to the comparative costs of building the 220/400 kV substations earlier.
95 Therefore, options 7.1, 7.2, and 8 should be discarded because they are more
costly than equivalent options
4.7 Non-qualifying
alternatives
96 The Grid Investment Test defines an ‘alternative’ in clause 19. Transpower
believes the options defined in section 4.4 meet the requirements of clauses 19.1,
19.4 and 19.5.
97 As discussed below, Transpower concludes that HVDC options and the High
Temperature Conductor option (Option 4) are not likely to proceed (Clause 19.3)
and not reasonably practicable (Clause 19.2) and therefore do not qualify as
alternatives.
4.7.1 HVDC
alternatives
98 Based on Tables 8.1 and 8.3 in the Commission’s draft determination, the HVDC
alternative in 2017 is more costly than either their 220 kV or 400 kV alternatives
in 2017. On this basis, Transpower has concluded that the 220 kV alternative
considered in this Amended Proposal is a reasonable surrogate for the HVDC
option. In other words, if the Transpower proposal is shown to be more cost
effective than the 220 kV proposal, then it will also be better than the HVDC
proposal.
99 Transpower has, as part of its Grid Vision3 considerations, assessed the options
of relocating the Haywards HVDC converter station to Bunnythorpe or Auckland
and found HVAC options to be more cost effective.
100 Transpower has also submitted an HVDC upgrade project in the September 2005
GUP. It has been suggested that there could be synergies between this project
and the North Island Upgrade project.
3 The summarised finding of the Grid Vision considerations were published in the Transpower
documents ‘Future of the National Grid’ December 2003 and October 2004.
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101 Moving one pole of the existing HVDC link to a point further north of Haywards,
including Auckland, would require the construction of a new HVDC line or
conversion of existing 220 kV lines to HVDC operation.
102 The time taken to consent a new HVDC line and the comparative costs of
building a line from Wellington to Auckland, in Transpower’s view, rule this option
out.
103 Converting existing 220 kV lines to HVDC operation is costly, would increase
congestion on the 220 kV grid and potentially restrict the ability to provide for both
southward transfers and the Wellington load.
104 In addition to the cost based arguments, Transpower has considered the
implications of the (draft) GPS. Clause 34A of the (draft) GPS requires that the
national transmission grid should be planned in such a way as to facilitate the
potential contribution of renewables to the electricity system and in a manner that
is consistent with the Government’s climate change and renewables policies.
Clauses 87A and 87B refer to facilitating renewables and requirements for
consistency with government policy relating to renewable generation and climate
change.
105 There is potential for significant development of renewables – mainly wind and
geothermal – in the central and southern North Island. Converting existing 220 kV
lines for HVDC operation would reduce the options for renewables to connect to
the 220kV grid because of the reduced capacity. Connection to HVDC is
expensive because of the cost of the converter stations.
106 HVDC links are generally point-to-point solutions and multi-terminal HVDC
installations are rare and not considered a mature technology, as indicated by the
following4:
“… the adoption of a three terminal dc link of the conventional type
for the Whakamaru-Auckland system would be a very costly
solution with limited flexibility for future transmission expansion.
On the other hand, …, the more flexible PWM multi-terminal
alternative is not really a contender for the large power rating
involved. Apart from the components (particularly the cable) costs,
the switching (due to high frequency) and transmission (due to the
high current) losses would be extremely high. “
“New Zealand’s previous commitment to dc (with the Cook Strait
scheme), was an obvious decision, as there was no practical
economic ac alternative at the time. However, the case for further
dc, and particularly the multi-terminal option, is far from obvious at
the moment and I would suggest a prudent “wait and see” policy in
this respect.”
107 Transpower has concluded that even if the proposed project does not proceed, it
is unlikely that this option would be built. The option is thus classed under Rule
19.3 as not qualifying as an alternative for formal comparison with the proposal.
4 “Use Of HVDC Multi Terminal Options For Future Upgrade Of The National Grid?”
Jos Arrillaga
Emeritus Professor, FIEE, FIEEE, MNZM, 24-May-2006.
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4.7.2
Option 4: Duplexing of Whakamaru-Otahuhu A&B lines with high
temperature conductor
108 This involves:
•
duplexing the Otahuhu – Whakamaru A & B single circuit lines with high
temperature conductor and connecting to Pakuranga from a transition station
in the vicinity of the South Auckland urban boundary through 220 kV cables.
The line section from Otahuhu to transition station will
not be duplexed and
will be disconnected but not dismantled;
•
re-conductor other existing circuits (for example, the Otahuhu - Whakamaru C
double circuit line) with high temperature conductor as required;
•
utilising series compensation to maximise the sharing of transmission flows
and extend transmission capability; and
•
details of the project and the sequencing of modelled projects are provided in
Attachment D.
109 Although Transpower considers this a non-qualifying alternative, Transpower
decided to undertake a comparative economic analysis because of the interest
shown in the option by some landowners and interest groups. The economic
analysis shows the option is not competitive and reasons for this are discussed
later in this document.
110 Aside from the economic results, Transpower has no experience with this type of
conductor and is not aware of any transmission lines of comparable length where
the conductor is relied on to operate for extended periods at high temperatures.
111 Transpower is therefore concerned at the potential risks of conductor failure,
particularly where the lines in question – the Otahuhu -Whakamaru A, B and C
lines – all have significant levels of residential under-build.
112 An increase in magnetic field of between two and three times is associated with
the substantial increase in current that is required to deliver the deferral benefits.
Transpower believes that ‘prudent avoidance’ of such substantial increases in
magnetic fields is appropriate, particularly where there are significant levels of
under-build.
113 Transpower has concluded that even if the proposed project does not proceed, it
is unlikely that this option would be built. The option is thus classed under Rule
19.3 as not qualifying as an alternative for formal comparison with the proposal,
although analysis in this application allows this comparison to be made to
demonstrate the economic cost of the project.
4.8 Electric and magnetic fields: transmission design issues for the
options
114 Transpower has adopted the ICNIRP Guidelines5 in designing 400 kV and 220 kV
options. Transpower expects the current standards to be relatively stable in the
long term but is aware that some utilities are voluntarily adopting lower standards
for magnetic field levels.
5 International Commission on Non-Ionizing Radiation Protection; “Guidelines For Limiting Exposure To
Time-Varying Electric, Magnetic, And Electromagnetic Fields (Up To 300 Ghz)” – 1998.
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115 Transpower notes that Option 3 and 4 involve duplexing and increasing the
current flow in the Otahuhu-Whakamaru A and B lines. These lines have many
dwellings and other buildings located directly under the lines and within the
easement boundaries.
116 While the electric field strength does not change (as the operating voltage
remains in the same range), the current related magnetic field will increase
(almost double) from existing levels. Nevertheless, the resulting magnetic field
strengths remain below the ICNIRP guidelines.
117 For the options in new corridors, the magnetic field strengths at the corridor
boundaries are well below those experienced directly under existing lines or
Option 3 or 4.
118 A further safeguard is provided for new lines through the purchase of easements
which ensure that the construction of dwellings or other substantial buildings are
prohibited within the easement boundaries.
4.9 Alternatives for further analysis
119 Limiting the options has resulted in three alternative projects that will be
compared against each other using the GIT with the aim of selecting a proposed
investment.
120 The projects are:
Option
Description
1
220 kV into Pakuranga and Otahuhu
2
220 kV – 400 kV staged to Pakuranga
400 kV into the South Auckland urban boundary and 220 kV
cables to Pakuranga and Otahuhu (deferred conversion to
400 kV)
3
220 kV augmentation – duplexing of Otahuhu -Whakamaru A&B
lines
Table 4-2. Alternative projects for further analysis
121 Each of these projects is, with respect to the Grid Investment Test Rule 19:
• Technically
feasible;
• Reasonably
practicable;
and
• Reasonably expected to provide similar benefits.
122 These projects are therefore considered as alternatives for the purposes of
applying the GIT. The alternative projects are summarised below.
4.9.1
Option 1: 220 kV into Pakuranga and Otahuhu
123 This involves
• Building a new
high capacity
220 kV double circuit transmission line
between Whakamaru and a transition station in the vicinity of the South
Auckland urban boundary, which will be series compensated when required.
• Installing 220 kV cables from the transition station to Pakuranga substation.
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• Building an additional 220 kV double circuit transmission line between
Whakamaru and Otahuhu (on a new route and preferably providing corridor
diversity) when the transfer capacity to the upper North Island is exhausted.
• Details of the project and the sequencing of modelled projects are provided in
Attachment D.
4.9.2
Option 2: 220 - 400 kV staged to Pakuranga:
124 This involves
• Building a 400 kV double circuit overhead line between a new substation
(Whakamaru North) located near the existing Whakamaru substation and a
transition station in the vicinity of the South Auckland urban boundary. Initially
the transition station will be connected to Pakuranga using 220 kV
underground cables.
• Subsequently, additional 220 kV cables will be used to transmit power from
the transition station to Otahuhu. The overhead transmission circuits will
initially operate at 220 kV and convert to 400 kV operation when required by
building 400 kV/220 kV switchyards at the South Auckland urban boundary
transition station and also at Whakamaru North.
• The overhead transmission circuits will be series compensated when required
to increase the transfer capacity to the upper North Island as long as possible
before conversion to 400 kV. When the transfer capacity is exhausted, the
transmission circuits will convert to 400 kV operation.
• Details of the project and the sequencing of modelled projects are provided in
Attachment D.
4.9.3
Option 3: Duplexing of Whakamaru-Otahuhu A&B lines
125 This involves
• duplexing the Otahuhu – Whakamaru A & B single circuit lines and
connecting to Pakuranga from a transition station in the vicinity of the South
Auckland urban boundary through 220 kV cables. The line section from
Otahuhu to transition station will not be duplexed and will be disconnected but
not dismantled;
• building a 220 kV line and subsequent investments after the capability
following the duplexing is exhausted; and
• details of the project and the sequencing of modelled projects are provided in
Attachment D.
4.10 Selecting the Proposed Investment
126 The three alternative projects identified above as well as the High Temperature
Conductor variant, were compared against each other using the GIT.
127 Transpower notes that there has been a considerable amount of discussion on
the GIT and its interpretation. In light of these discussions, Transpower has
agreed to use the GIT calculation tool designed by the Commission for selecting
the Amended Proposal on the understanding that the tool is still evolving.
Transpower hopes to continue to develop the GIT calculation tool with the
Commission over time.
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128 A detailed description of how the GIT was applied and the results of the analysis
is provided in Attachment E, which describes how the proposed investment was
selected as being Option 2: 220 - 400 kV staged to Pakuranga.
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5
Transpower’s Amended Proposal
129 Transpower is seeking approval for the reliability investment as defined in
paragraph 12. This project is Option 2, 220 kV - 400 kV staged to Pakuranga, as
described in the previous section.
130 Many of the final design details will depend on, amongst other factors (and
subject to this approval):
• The outcomes of the RMA approval process and requisite consultation phase;
• The availability of property and easements;
• Detailed design of substations, towers and cable routes; and
• Commercial negotiations with suppliers and contractors.
131 The purpose of this section is to set out a likely form that the proposal would take
at a more detailed level, for the purposes of public information and the
Commission’s approval process. Transpower does not seek approval at the level
of detail set out in this section, and Transpower confirms that it seeks approval for
the project as defined and described in paragraph 12.
5.1 Proposal description and timetable
132 The proposed investment is for a 400 kV overhead transmission line from
Whakamaru North into the transition station, with 220 kV cables into Pakuranga
and Otahuhu substations (option 2 as described above).
133 This option comprises building the new 400 kV transmission line, along with the
projects identified as ‘common’ augmentations listed in Attachment D.
134 The 400 kV transmission line has a system need date of 2013 and will be initially
operated at 220 kV increasing the transfer limit to the Upper North Island to
approximately 3,400 MW.
135 In 2022, the new line may be 55% series compensated, which along with other
developments, increases the transfer limit to approximately 4,500MW. A further
cable connection into Auckland will be provided at this stage.
136 By 2034, the line needs to be upgraded to 400 kV operation, by commissioning
new 400 kV sub-stations at Otahuhu and Whakamaru. Along with other
developments, the transfer limit increases to approximately 5,500 MW.
137 The thermal and the reactive development plans for the proposed investment are
shown in the tables below and as well as pictorially in Figure 5.1.
138 The ‘Year’ column represents the year in which the ‘Augmentation’ is required to
be commissioned for a high load growth scenario. Lower load growth would
result in these augmentations being deferred. With respect to dates, 2013 means
the augmentation must be commissioned by winter 2013.
139 Table 5.1 shows the development plan in terms of system needs dates. These
dates represent the absolute latest that the augmentations must be
commissioned by and
it provides no allowance for risks caused by such events
as delays in procurement or obtaining consents etc.
140 Project risk and its effect on the timing in relation to the proposal is discussed in
section 7.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Year
Augmentation
2009 Install 250 MVAr static reactive plant at Otahuhu
Decommission the 110 kV Arapuni - Pakuranga line
2010
Install 100 MVAr static reactive plant at Otahuhu
Establish Drury switching station and implement thermal upgrade for
2012
Otahuhu-Whakamaru C line
New substation at Whakamaru North
2 x 400 kV Whakamaru North – Transition Station circuits operated at 220 kV
2 x 220 kV Cables, Transition Station - Pakuranga
Cable Transition Station in the vicinity of the South Auckland urban boundary
2013
220 kV sub station at Pakuranga
Increase operating voltage of Otahuhu -Pakuranga to 220 kV *
Install 3 x 120 MVA supply transformers at Pakuranga
First 220 kV Pakuranga-Penrose Cable
2014 Reconductor 110 kV ARI-HAM 1 & 2 to Nitrogen 75°C conductors.
2016
Install 100 MVAr static reactive plant at Otahuhu
2017
Install 100 MVAr static reactive plant at Otahuhu
Second Pakuranga-Penrose cable
2018
Install 100 MVAr dynamic reactive plant at Otahuhu
2020 Install 100 MVAr static reactive plant at Huntly
2 x 55% compensation on Whakamaru -Transition Station circuits
Install 110 kV OTA-WIR cable; close the WIR bus breaker
2022 1 x 220 kV Penrose- Otahuhu cable
Commission switching station at South Auckland urban boundary
1 x 220 kV Transition Station - Otahuhu cable
Install 200 MVAr static reactive plant at Otahuhu
2024
Second 220 kV Otahuhu - Transition Station cable
Install 100 MVAr dynamic reactive plant at Otahuhu
2025
Second Roskill 220 / 110 kV transformer
2027 Re-conductor HAM-BOB 110 kV circuits to Nitrogen Conductors.
Continued on next page
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Install 100 MVAr static reactive plant at Huntly
2028 Thermal upgrade of HLE- Whakamaru section of Otahuhu - Whakamaru C line
Second 220 kV Penrose - Roskill cable
Install 150 MVAr static reactive plant at Otahuhu
2029
Install 20 Ohm reactor on Otahuhu - Whakamaru A&B lines
2031 Install 100 MVAr static reactive plant at Huntly
Install 300 MVAr dynamic reactive plant at Otahuhu
2032
Forced cooling on Transition Station -Pak cables
Install 150 MVAr static reactive plant at Otahuhu
2033
Third Roskill 220 / 110kV transformer
Forced cooling on 220 kV Transition Station - Otahuhu cables
400 kV sub station at Whakamaru North
400 kV sub station at the transition station in the vicinity of the South Auckland
urban boundary
Operate Whakamaru - Transition Station at 400 kV
2034
6 x 400/220 kV 600 MVA transformers at Transition Station
6 x 400/220 kV 600 MVA transformers at Whakamaru
Reduce series compensation on the 400 kV line to 45%
Second 220 kV Penrose-Otahuhu cable
New Otahuhu 220/110 kV transformers in parallel with T3 and T5
2038
1 x 75 MVA phase shifting transformer on Arapuni-Bombay circuit
Install 300 MVAr static reactive plant at Otahuhu
2042 Post contingency Operational Measures to reduce Transition station - Otahuhu
loading
* Transpower will consult on both AIS and GIS switchyard at Pakuranga. Only if there is a clear
public preference for a GIS switchyard at Pakuranga will the designation be limited to this option,
and thus the GIS referred to above would have to be built.
** This list excludes augmentations that are common to all of the alternatives. For the common
projects, refer to Attachment D (Technical Assessment of Modified Options)
Table 5-1: System need dates under the proposed investment,
showing projects included in this proposal in bold.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
HOB
ROS
New 220 kV cables
New Transformer
Existing 110 kV
Reconnected
New 220 kV cable
New 220 kV
Decommissioned
circuits operated
And Voltage Uprated
& series Reactor
New 220 kV
Substation
at 220 kV
cables
139/114 MVA
PEN
PEN
PAK
A
A
Replace OTA
PAK
V
V
A
A
V
T2 & T4
New 220 kV cables
V
M
M
9
9
M
M
3
7
46
46
7
MNG
ROS
HEN SWN
4
2/
2/
1/1
2/3
49
49
19
38
Uprated Circuits
Decommissioned
OTA
OTA Split
Uprated
A A
Circuits
New cable
-OT
A
A
A
A
Y
V
V
V
TAK
A
HL
MV
A
A
Bussing HLY-OTA
4 M
V
New 220 kV
M
V
WIR
95 M
14
2
cables
A at Drury
A
MV
2
V
/6
/61
5/6
0
4 M
4 M
9
1/9
7
76
670
6
New 220 kV
01/
10
95 M
0/61
0/61
cables
1
Series
GLN
Drury
/6
Reactors
67
67
BOB
5
6
ORM
7
New Transformer
HLY
HLE
A
A
Uprated
V
V
Circuits
ORM
New 220 kV
Substation
M
M
2
WES
2
/12
/12
Bussing OTA-WKM C
New 400 kV
134
134
line at HLE
Substation
A
A
MV
TWH
HAM
MV
HAM
1
5
/114
0
A
A
A
A
62/
14
V
MV
MV
0
Series
MV
M
70
7
A
A
Compensation
V
V
2
2
/4
2
2
3/4
1
1
4/
493
49
14 M
14 M
34/
/6
/6
1
13
Uprated Circuits
0
0
67
67
ARI
A
C
M
Phase Shifting
Transformer
SFD
-WK
New 400 kV circuits
Y-
- initially operated at 220 kV
KIN
HTI
ONG
HL
OTA
M B
M A
K
K
New 400/220 kV substation
-W
-W
OTA
OTA
WKM
MTI
MOK
Uprated Circuits
WKM
Uprated Circuits
Legend
TMN
TKU
WRK
ATI
400 kV
NPL
220 kV
Bussing second HLY-SFD
110 kV
circuit at TMN
Cables
WKM
Generating Station
SFD
WKM
Substation
Common Augmentations
Option Specific Augmentation
BRK
Option Specific Decommission
Figure 5-1. Single Line Diagram for Proposed Investment
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
5.2 Proposal
costs
141 Transpower is seeking Commission approval for costs incurred by Transpower in
the implementation of the Amended Proposal. The estimated capital cost for the
Amended Proposal is $585m in $2006, including contingencies ($509m excluding
contingencies).
Estimated
Estimated
Cost
Category
Item
Cost $m
including
(2006)
Contingencies
$m (2006)
Preliminary engineering, environmental
Investigations
22
22
and property work.
Property
Acquisition of property rights
96
96
Acquisition of designations and
Environmental
7
7
resource consents.
2x400kV circuits from Whakamaru to a
Transmission
transition station in the vicinity of the
168
210
Works
South Auckland urban boundary
operated at 220kV
Other Lines Works
6
7
Substation Works
87*
101*
Cable
91
104
Dismantling
Arapuni to Pakuranga Line
4
5
Project
28
33
Management
Total
509
585
*This cost will increase by between $7M and $10M if the Otahuhu diversity project does not proceed.
Table 5-2. Estimated Costs for Proposal
(The projects included in these cost estimates are those described in Table 7-2.)
142 To determine an amount for its approval request Transpower has estimated the
mid-point and 90% limit of project costs using a simulation technique (see detail
in 5.2.1) on commissioning of the first major stage of the proposal.
143 The mean project cost estimate in December 2011 dollars is $764M. The 90%
limit of project costs has been estimated at $824M. The chart below shows the
distribution of project costs.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Distribution of Simulated Capital Cost
8%
10%=$713m
Mean=$764m
90%=$824m
7%
6%
5%
y
nc
ue 4%
q
re
F
3%
2%
1%
0%
654
677
699
722
744
767
789
811
834
856
879
$m 2011
Figure 5-2. Distribution of project costs
144 The following table shows the Amended Proposal costs without simulation. The
total cost is expected to equal $764M, in $2011, which includes a $117M inflation
adjustment.
Fully
Fully
Cost
Exchange
Interest
Conting
Adjusted
Adjusted
Category
$m
Rate
During
Inflation
encies
Cost $m
Cost $m
(2006)
Variation
Construction
(2006)
(2011)
Investigations
22
0
0
0
22
5
27
Property
96
0
0
12
108
20
128
Environmental
7
0
0
2
9
2
11
Lines
174
43
0
29
246
44
290
Substations*
87
13
0
4
104
18
122
Cable
91
13
0
8
112
21
133
Decommissioning
4
1
0
0
5
1
6
Project
Management
28
6
0
7
41
6
47
Total
509
76
0
62
647
117
764
*These costs will increase by between $7M and $10M if the Otahuhu diversity project does not proceed.
Table 5-3. Proposal costs without simulation
145 Including simulation, a 90% upper limit on project cost is expected to equal $824
M, in $2011, which includes a $141M inflation adjustment.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Cost
Exchange
Interest
90% Cost
90% Cost
Conting
Category
$m
Rate
During
Limit
Inflation
Limit
encies
(2006)
Variation
Construction
$m (2006)
$m (2011)
Investigations
22
0
0
0
22
5
27
Property
96
0
0
13
109
23
132
Environmental
7
0
0
2
9
2
11
Lines
174
46
14
30
264
52
316
Substations*
87
18
4
5
114
22
136
Cable
91
16
3
9
119
27
146
Decommissioning
4
1
0
0
5
1
6
Project
Management
28
6
0
7
41
9
50
Total
509
87
21
66
683
141
824
*This cost will increase by between $7M and $10M if the Otahuhu diversity project does not proceed.
Table 5-4. Proposal costs with simulation
5.2.1
Method for Estimating 90% Cost Limit
146 The Monte Carlo technique was used to estimate the mid-point and 90% limit on
project costs. The cost of the Amended Proposal is simulated a large number of
times, and the frequency of simulation results is used to establish costs for a
given level of likelihood.
147 Costs for projects and other elements of the proposal are broken down into
components including:
• Costs denominated in New Zealand dollars
• Costs denominated in other currencies
• Property
costs
148 The projects occur on a staggered basis and costs have been streamed over
various dates to reflect project timing, and to allow calculation of interest during
construction6.
149 The model takes into account the following variables:
• Exchange
rates
• Inflation
• Real interest rates
• Property cost escalation
• Price
accuracy
• Scope
contingencies
150 Cost estimates also include an allowance for interest during construction.
6 For property purchases it has been assumed that if the proposal is approved the cost of land and easements can be
included in Transpower’s revenue base once route acquisition has been completed. Interest during construction
costs will be higher if these costs must be incurred until completion of the transmission line, and lower if
Transpower can recover these costs from the time of the land acquisition.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
5.2.2
Assumptions for Key Variables
Exchange Rates
151 Point estimates of capital cost were based on 10 year average exchange rates.
These were subsequently adjusted to smoothed spot rates using the average
exchange rate 20 business days either side of 30 June 2006. For the simulation
runs exchange rates have been sampled from daily exchange rates over the
period 1 July 1996 to 30 June 2006. This approach ensures that the simulated
exchange rates and cross-rates have a similar mean and variance to historical
rates. Over a large number of simulations the exchange rate will be close to the
10-year average rate.
Inflation
152 Inflation is modelled by drawing from a uniform distribution in a range from 2% to
4%.
Real Interest Rates
153 The real interest rate is modelled by drawing from a uniform distribution in a
range from 6% to 8%. The nominal interest rate is the real interest rate plus the
inflation rate.
Property Cost Escalation
154 Real property cost escalation (i.e. price escalation over and above the inflation
rate) is modelled by drawing from a uniform distribution in a range from 2% to
4%.
Price Accuracy
155 As regulatory approval occurs prior to the issuing of tenders, there is uncertainty
over the price of equipment to be installed. This has been modelled by
expressing the accuracy of estimates as a triangular distribution. The point
estimate of costs is given as the most likely outcome, and lower and upper
bounds are expressed as percentages of the midpoint.
Lower
Upper
Price Accuracy Parameters
Limit
Limit
Static compensation
-12.5%
12.5%
Decommission 110kV ARI-PAK Line
-5.5%
5.5%
Drury Switching Station
-12.5%
12.5%
OTA-WKM C thermal upgrade
10.0%
10.0%
2x400kV WKM-ORM ccts operated at 220kV
-5.5%
5.5%
WKM & WKN Sub work
-11.5%
11.5%
OTA Enabling Work
-10.0%
10.0%
OTA Subs Work
-10.0%
10.0%
2x220kV ORM-PAK cables
-10.0%
10.0%
Cable Termination at ORM
-11.5%
11.5%
220kV substation at PAK
-9.5%
9.5%
Convert OTA-PAK 110kV ccts to 220kV
-10.0%
10.0%
Table 5-5. Price accuracy
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Scope Contingency
156 Scope contingencies have been included to cover two distinct categories of costs:
Costs for works which are planned, but which have not been included in the cost
estimates except through a general allowance, and costs for works not
anticipated at the time costs were estimated.
157 For the purpose of simulation modelling, scope contingencies have been treated
as fixed percentages, i.e. scope contingencies as a percent of costs do not vary
between simulations. They may vary in dollar terms because of changes in other
input variables. This is consistent with the definition of expected costs used in
the economic analysis.
5.2.3
Comparison of Costs with September 2005 GUP
158 This subsection compares the approval cost estimates in Transpower’s original
April 2005 submission, and September 2005 GUP7 with the new approval cost
estimates for the Amended Proposal. A straight comparison is meaningless as
the GUP cost estimates were expressed in nominal terms and the amended
project costs are in December 2011 dollars, consistent with the Commission’s
approach in its Draft Decision.
April 2005 Submission/
Amended Project
Cost Category
Sept 2005 GUP
Sept 2006
$2005
Nominal $2011
$2006
$2011
Investigations
20
25
22
27
Property
97
121
96
116
Environmental
11
14
7
8
Transmission Works
- Lines 400kV Line
120
150
168
203
Uprate section of Ota-Wkm C
3
4
Ota-Pak 110kV Circuits
1*
1*
Drury Switching Station
2
2
- Subs
Otahuhu
66
82
10
12
Whakamaru
33
41
11
13
Pakuranga
46
55
Drury Switching Station
13
16
Static Compensation
7
8
- Cable
84
105
91
110
Dismantling
4
5
4
5
Project Management
25
31
28
34
Subtotal
460
460
575
509
614
Inflation
39
104*
141*
Contingency
60
65
75
87
105
Exchange Rate
-6
-6
-7
21
25
Interest During Construction
59
64
74
66
80
Total
573
622
716
683
824
Adjustment for difference in Limits**
-7
Total
573
622
709
683
824
*This cost will increase by between $7M and $10M if the Otahuhu diversity project does not proceed.
Table 5-6. Cost summary
7 Volume 2, Section 5, Tables 6.1 and 7.2.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Note that for the orange columns inflation figures are included to show the scale of the price
adjustments made to the original estimates. They are not included in the summation.
** The April 2005 estimates were 95% upper limits compared to the 90% limit Transpower is now using.
Analysis of the September 2005 GUP calculations suggest that the difference between 95% and 90%
cost limits would have been $7m in $2011.
159 Table 5-6 shows both sets of figures adjusted to December 2011. These are the
orange columns. The other columns show the amounts in dollars at other points
in time so that they can be compared to costs in the September 2005 GUP, and
this proposal.
160 The important differences between the costs for the original proposal and those
for the Amended Proposal are:
• Lines costs rise $60m – reflecting the higher carrying capacity of the line, and
costs to convert the Otahuhu – Pakuranga 110kV lines to 220kV, and to
up-rate sections of the Otahuhu-Whakamaru C line to 80˚C.
• Substation costs drop $19m. This would be more but the 2005 GUP
submissions did not include short term augmentation projects, or static
compensation costs prior to the major project. These costs amount to $26m.
• Contingency allowances rise $30m. This reflects the use of fixed “Scope”
contingencies in the estimates for the Amended Proposal. In preparing the
2005 GUP estimates these were assumed to be variable with a mean of zero.
• Exchange rate allowances rise $32m. This reflects an alternative treatment of
exchange rate volatility. The original estimates covered Transpower for
relatively modest exchange rate swings.
5.3 Proposal is a reliability investment
161 Part A of the Electricity Governance Rules defines a reliability investment as
“investments by Transpower in the grid, or alternative arrangements by
Transpower, the primary effect of which is, or would be, to reduce
expected
unserved energy”. Expected unserved energy is defined in Part A as meaning “a
forecast of the aggregate amount by which the demand for electricity exceeds the
supply of electricity at each grid exit point as a result of likely planned or
unplanned outages of primary transmission equipment”.
162 The need for new investment to reduce expected unserved energy in the upper
North Island is demonstrated in Part II, Volume II of Transpower’s September
2005 GUP and in section 3 of this proposal. The “needs analysis” in the original
Volume II of the GUP concluded that “there is some risk of electricity demand not
being supplied into the upper North Island at times of peak loading from 2010 and
that new investment is required to maintain security of supply into the region.”8
The Commission, in paragraph 5.1.6 of its draft decision on the original Volume II
proposal, stated it was “satisfied … that the proposal would have the primary
effect of reducing unserved energy and therefore it is appropriate to consider it as
a reliability investment under rule 13.”
163 The Amended Proposal outlined in this application is also designed to reduce the
expected unserved energy identified in the needs analysis referred to above,
therefore the Amended Proposal is, in Transpower’s view, also a reliability
investment.
8 P5, Volume II, Transpower GUP, September 2005
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
164 The Amended Proposal is for a new transmission link between
Pakuranga/Otahuhu and Whakamaru. The Commission’s determination on the
Core Grid defines this line as being included within the Core Grid. Because the
line is part of the Core Grid both parts of the Grid Reliability Standards (GRS) , as
defined in the glossary of this application, are relevant to this Amended Proposal.
That is both the probabilistic (identified in rule 4.1 of Schedule F3) and the
deterministic (identified in rule 4.2 of Schedule F3) standards are applicable to
the assessment of the Amended Proposal.
5.4 Proposal is an amendment
165 On 31 May 2006 Transpower informed the Commission of its intention to amend
the 400 kV Project in response to, among other things, various requests for
information from the Commission. This current application, of an amendment to
the 400 kV Project in the Original GUP, has been agreed with the Commission.
166 A salient difference between the Original Proposal and the Amended Proposal is
that the new line initially terminates into Pakuranga substation, with a termination
into Otahuhu being provided in the future. This is illustrated in the diagram below.
The Original Proposal included the termination of the new line into Otahuhu only.
Figure 5-3. New line into Auckland (indicative only)
167 Other principal ways in which the Amended Proposal varies from the Original
Proposal include:
• The overhead line component is amended such that it will be staged. Rather
than operate at 400 kV from commissioning, it will operate initially at 220 kV.
When it becomes economic to do so, approval will be sought for installation of
the 220/400 kV transformers to enable 400 kV operation;
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
• The transmission capability of the overhead line has been increased to
2700 MVA to improve the utilisation of the transmission corridor and defer the
need for a further corridor;
• The underground cable components are amended to operate at 220 kV rather
than 400 kV;
• Short term projects are included in the proposal to defer the need for the
major project to 2013 (details in paragraph 12); and
• Commissioning of the short term projects is targeted for 2010 with the major
works in 2011; and
• A new 220kV substation is required at Pakuranga.
168 This application presents for approval this Amended Proposal by reference to the
Asset Management Plan and information on investment contracts contained in
the Original GUP.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
6
The Amended Proposal meets the requirements of the
Rules
169 Rule 13.4 sets out three criteria that a proposed reliability investment must meet
in order to gain approval from the Commission. These criteria, and a discussion
as to why Transpower’s Amended Proposal meets these criteria, are set out in
the following subsections.
6.1 Rule 13.4.1.1: The Amended Proposal demonstrates GEIP in
meeting the GRS
170 The first criteria for approval under Rule 13.4.1 requires that the proposed
reliability investment:
13.4.1.1
“reflects good electricity industry practice in meeting grid
reliability standards”
171 In its draft decision, the Commission considered that Rule 13.4.1.1 is not entirely
clear, but took a view that in determining whether the Rule has been complied
with, the Commission must turn its mind to whether it is satisfied that the
proposed investment both:
• meets the GRS; and
• in so doing, reflects good electricity industry practice (GEIP).
172 Transpower agrees that the proposed investment must meet both of these
criteria. Transpower’s view is that this GEIP applies in addition to how one
interprets the GRS, i.e. that under this Rule GEIP and the GRS are not
independent. In other words, this rule is more than two independent rules “reflect
good electricity industry practice” and “meet grid reliability standards”.
173 The following three sections are therefore ordered to cover in turn:
• the
GRS
• reflects GEIP; and
• reflect GEIP in meeting the GRS
6.1.1 The
GRS
174 The GRS are contained in Schedule F3, which states that:
4
“For the purpose of clause 3, the grid satisfies the grid
reliability standards if:
4.1
the power system is reasonably expected to achieve a
level of reliability at or above the level that would be
achieved if all economic reliability investments were to be
implemented; and
4.2
with all assets that are reasonably expected to be in
service, the power system would remain in a satisfactory
state during and following any single credible
contingency event occurring on the core grid.”
175 Rule 4.1 is the so-called “probabilistic limb of the GRS”, and Rule 4.2 the
“deterministic limb of the GRS”. On a case by case basis, whichever limb
provides the higher standard drives the reliability standard.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
176 Transpower notes that on occasion the terms “economic limb” and “standards
limb” of the GRS have been used instead. This is potentially misleading, as both
limbs have economic and standards-based components in their formulation and
application.
177 The deterministic limb provides a safety net for the probabilistic limb for
contingencies on the core grid.
The probabilistic limb of the GRS
178 As defined in the GRS:
“Economic reliability investments” means investments in the grid and
transmission alternatives that would satisfy the Grid Investment Test:
8.1.
reading each reference to a proposed investment in the
Grid Investment Test as a reference to the grid
investment or transmission alternative (as the case may
be); and
8.2.
having regard to part C of these rules including the policy
statement set out in schedule C4.
179 The proposal (and the alternatives under the GIT being considered) is for a grid
investment. For the proposal, clause 4.1 of the GIT therefore implies:
the power system is reasonably expected to achieve a level of
reliability at or above the level that would be achieved if:
•
all investments in the grid that would satisfy the GIT were to
be implemented,
•
having regard to part C of these rules including the policy
statement set out in schedule C4.
180 The proposal satisfies the GIT, as detailed in section 6.3 “Rule 13.4.1.3: The
Amended Proposal satisfies the Grid Investment Test”, so the first part of the test
would be achieved were the proposal to be implemented.
181 The relevant components of Part C including C4 of the Rules detail the manner in
which security is maintained for contingent events. In essence, the system is
operated in real time to a security level of n-1 with all assets made available to
the System Operator. It is the asset owners, principally the grid owner and
generators, who determine what assets are made available.
182 These are not reasons not to use the GIT as part of the reliability standards.
However they are relevant factors in considering how to interpret the deterministic
“safety net” limb of the GRS.
183 For example, if one had total confidence in the accuracy and applicability of the
GIT, one would not need a deterministic safety net. This is not the case in New
Zealand, nor anywhere to Transpower’s knowledge. The Rules accept that this is
the case, as did the Commission in recommending those Rules:
184 Limitations of a pure probabilistic approach and a similar Grid Investment Test
have been recognised by VENCorp, the transmission planner for Victoria,
Australia:
“This 25 year vision indicated:
• The long term economic benefits of efficient high capacity
infrastructure such as the 500 kV electricity transmission network
established by Victoria three decades ago. It is not clear that this
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backbone network would have emerged if current transmission
planning approaches had been used at the time.9
The deterministic limb of the GRS
185 The “deterministic limb” of the GRS requires that
The grid satisfies the grid reliability standards if, with all assets that
are reasonably expected to be in service, the power system would
remain in a satisfactory state during and following any single credible
contingency event occurring on the core grid.”
186 This is akin to the manner in which the system is operated, as described above.
187 Transpower has interpreted this deterministic limb to mean n-1 (the power system
would remain in a satisfactory state during and following any single credible
contingency event occurring on the core grid) with one generator out of service
(with all assets that are reasonably expected to be in service). This standard is
known as n-g-1, being short-hand for n-1 with the largest generator out of service.
188 The Commission, in its draft decision, appears to have misinterpreted
Transpower’s position, stating that:
“[Transpower considers it] reasonable to expect that a generating unit
(eg a unit at Otahuhu B) will always be out of service. The
Commission accepts that generating plant will be out of service from
time to time, but does not consider it reasonable to assume that one
generating unit will always be out of service”
189 For clarity, Transpower does not consider it reasonable to expect that a
generating unit will always be out of service. Transpower does consider it
reasonable and prudent to plan on being able to maintain n-1 security when a
generating unit (e.g. a unit at Otahuhu B) is out of service.
190 The Commission, in its draft decision, argues that its interpretation of the GRS
delivers the same outcome as Transpower’s interpretation of the deterministic
limb of the GRS:
“As it happens, while Transpower’s and the Commission’s
interpretation of the GRS is different, there is no practical difference in
this case: in analysing the need for investment in respect of providing
supply into Auckland, both approaches result in the same n-g-1 supply
security outcome”
191 Transpower does not fully agree with this assessment, as Transpower believes
that GEIP in meeting the GRS requires meeting n-g-1 at a prudently high demand
forecast, whereas Transpower understands that the Commission’s assessment of
the alternative proposals that it used in its draft decision met n-g-1 at a medium
growth forecast.
192 Notwithstanding this, Transpower agrees that this potential difference is not
relevant to approving this proposal under Rule 13.4.1.1, because if the proposal
meets n-g-1 at a prudently high demand forecast it will certainly meet n-g-1 at a
medium growth forecast.
9 “Vision 2030 – 25 year vision for Victoria’s Energy Transmission Networks” October 2005,
VENCorp, Australia.
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6.1.2
Definition of “Good Electricity Industry Practice”
193 Good electricity industry practice or GEIP is not a defined term in the Rules. In its
draft decision, the Commission developed a definition of GEIP through reference
to Transpower’s definition in its posted terms and conditions, and the Australian
definition, as:
“the exercise of that degree of skill, diligence, prudence, foresight and
economic management, as determined by reference to good
international practice, which would reasonably be expected from a
skilled and experienced asset owner engaged in the management of a
transmission network under conditions comparable to those applicable
to the relevant grid assets consistent with applicable law, safety and
environmental protection. The determination is to take into account
factors such as the relative size, duty, age and technological status of
the relevant transmission network and the applicable law.”
194 The Commission in its draft decision considered that this definition is appropriate
for the purposes of the application of Rule 13.4.1.1, with some additional factors
including:
• Performance criteria such as voltage stability margins, steady state bus
voltage ranges and transmission asset loading limits. The Commission
considers that many of the performance criteria detailed in Transpower’s
“Main Transmission Planning Guidelines”10 are sufficient to ensure that the
grid is planned to GEIP.
• Reliance, for substantial power system investments, on the use of equipment
and designs whose performance can be directly related to proven service
experience.
• A high degree of quality assurance applied in planning, design, manufacture,
commissioning, testing and maintenance activities.
• In its draft decision, the Commission considered that for a proposed
investment to meet GEIP, the following would be required:
o a robust design process, with consultation and involvement of customers
and stakeholders;
o well developed specifications and design documents;
o high-quality manufacturing and software development processes;
o extensive co-ordination and testing before and after system integration
phase;
o as far as possible, full factory testing of complete finished control and
protection systems;
o thorough checking and testing at site/commissioning; and
o ongoing validation and diagnostic maintenance.
195 Transpower agrees that the Commission’s definition provides a useful working
basis, and that the above factors are relevant considerations of GEIP. However,
Transpower’s view is that for transmission planning, there is more to GEIP than
included in these factors.
10This report is available as a supporting document to the Proposal on Transpower’s website:
www.transpower.co.nz.
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6.1.3
GEIP in meeting the GRS
196 In particular, GEIP requires amongst other things prudence as determined by
reference to good international practice. In the case of the proposal, GEIP also
would require consideration of the size, nature and importance of the Auckland
load.
197 Transpower maintains that for a critical load like Auckland, the minimum
acceptable standard for reliability would be one where peak demands could be
reliably supplied even with a critical generator, such as the Otahuhu CCGT, out of
service.
198 This approach is consistent with the short- and medium-term operational planning
processes used by the System Operator to ensure supply adequacy and
reliability. The System Operator has used this approach historically and has
demonstrated its efficacy over many years.
199 International references confirm the n-g-1 approach, or a standards-based
equivalent, to be consistent with international practice11,12 and therefore an
important indicator of GEIP.
200 In the Australian National Electricity Market, supply adequacy is treated
separately from grid reliability by means of a minimum reserve margin (in MW)
that must be maintained. For regions at the ends of the NEM power system
(Queensland and South Australia), the minimum reserve margin is at or greater
than the size of the largest unit. The approach is therefore consistent with an n-g-
1 approach for Auckland.
201 Transpower maintains further that, even if the Commission disagrees with
Transpower’s interpretation of the GRS and interprets it as n-1, assuming all
generation is available at 100% of its rated capacity, the requirement to consider
GEIP would necessitate taking into consideration international practice described
above.
11 PJM CETL process described at http://www.pjm.com/planning/downloads/cetlproc.pdf
12http://www.electricitycommission.govt.nz/pdfs/opdev/transmis/400Kv/supdocs/memoreport0
4.pdf
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6.2 Rule 13.4.1.2: The Original GUP complies with Rule processes
202 The second criterion for approval under Rule 13.4.1 requires that the proposed
reliability investment:
13.4.1.2
“complies with the processes set out in these Rules”.
203 In its draft decision, the Commission considered that this Rule should be
interpreted as requiring Transpower to comply with the processes stipulated by
Section III of Part F in relation to the submission of a proposed investment under
a GUP. The relevant processes are summarised by the Commission in its
consultation paper on the draft decision, in paragraph 6.3.5. Table 6.1 below re-
states these processes, and the actions Transpower undertook to meet the
process requirements:
Processes required by
Transpower fulfilled these requirements:
Rules 12 and 13
•
submitting a GUP to the
On 23 May 2005 the Commission sent a written
Commission within three
request to Transpower to prepare a GUP, and to
months of receiving a submit this by 24 August 2005. Following
written request from the
discussions between the Commission and
Commission, or such Transpower, in August 2005 this deadline was
other date as the extended to 30 September 2005. The Original GUP
Commission agrees (Rule
was submitted on this date.
12.2);
•
providing such content in
Rule 12.3 requires a GUP to include:
the GUP as required by
12.3.1 a comprehensive plan for asset management
Rule 12.3;
and operation of the grid
12.3.2 information on investment contracts
12.3.3 the proposed reliability and / or economic
investments, with supporting information
12.3.4 such other information as prescribed by the
Commission Board.
The Original GUP submitted on 30 September 2005
included Transpower’s most recent Asset
Management Plan (Vol. I), a list of bi-lateral
investment contracts that had been entered into up
to September 2005 (Vol I), the proposed 400 kV
upgrade into Auckland as a reliability investment
(Vol. II), and the proposed upgrade to the HVDC
link as an economic investment (Vol. III). Two other
investment proposals were included as economic
investments in Vol. IV, which was submitted on 31
October 2005. There was no extra content
prescribed in writing from the Commission Board,
under rule 12.3.4.
• complying with the In its consultation paper on its draft decision, the
timetable for consultation
Commission summarised the development of the
and approval of the consultation timetable, including extensions to this
investment under
timetable. In paragraph 7.2.8 of the consultation
consideration as agreed paper the Commission confirmed it was satisfied
by the Commission and
Transpower had complied with the extended
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Transpower or stipulated
timetable.
by the Commission (Rule
13.2); and
• answering
the Appendix 2 of the draft decision consultation paper
Commission’s questions lists in a table key relevant events and processes,
and carrying out
up to the publication of the consultation paper itself.
investigations and
This table includes the various requests for
evaluations as required information made by the Commission under Rule
by the Commission under
13.3.3. In paragraph 7.2.10 of the consultation
Rule 13.3.3.
paper the Commission stated it believed
Transpower had endeavoured to respond to these
requests to the extent practicable.
Table 6.1: Compliance with the Rule processes (‘Commission’ refers
to the Commission’
204 Transpower notes that in its draft decision, with respect to Transpower’s Original
Proposal, the Commission determined that:
“On balance, the Commission is … satisfied that Transpower has
complied with the processes set out in the relevant Rules.”
205 That the Amended Proposal follows the Rules process for an amendment by
Transpower to a reliability proposal is demonstrated in this section of the
application.
206 The Original Proposal and the amendment of it to form this Amended Proposal
therefore comply with the processes set out in the Rules.
207 Transpower considers that the Original GUP submitted on 30 September 2005,
and the Amended Proposal which is the subject of this application, demonstrate
compliance with the Rules for amending the Original Proposal, and hence meet
the requirements of Rule 13.4.1.2 that the “proposed reliability investment …
complies with the processes set out in these Rules”.
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6.3 Rule 13.4.1.3: The Amended Proposal satisfies the Grid Investment
Test
208 The third criteria for approval under Rule 13.4.1 requires that the proposed
reliability investment:
13.4.1.3
“meets the requirements of the Grid Investment Test”.
209 Clause 4 of the GIT states that a proposed investment that is necessary to meet
the reliability standard13 satisfies the Grid Investment Test if the Board is
reasonably satisfied that:
4.1.1.
the proposed investment maximises the expected net
market benefit or minimises the expected net market cost
compared with a number of alternative projects; and
4.1.2.
if sensitivity analysis is conducted, a conclusion that a
proposed investment satisfies clause 4.1.1 is sufficiently
robust having regard to the results of that sensitivity
analysis;
210 The purpose of this section is therefore to satisfy the Commission that the
Amended Proposal maximises the expected net market benefit, or minimises the
expected net market cost, compared with a number of alternative projects, in a
robust manner with respect to sensitivity analysis14.
211 The remainder of the GIT consists of the methodology for applying the GIT
(clauses 5 to 17) and the definitions to be used (clauses 18 to 32).
212 Table 6-2 presents the summarised rankings of the proposal and alternatives as
a result of the application of the Grid Investment Test.
213 The results in table 6-2 show that the proposed investment (Option 2) passes
Clause 4.1.1 of the GIT by having the lowest expected net market cost of the
three alternatives. The results in table 6-2 are in 2006 dollars; results in 2011
dollars are presented in Attachment E.
13 Different GIT clauses apply to economic investments. The Amended Proposal is a
reliability investment, and hence clauses 4.1.1 and 4.1.2 apply. See section 5.3.
14 Assuming that, given the size of the proposal, sensitivity analysis is conducted.
Transpower has conducted sensitivity analysis, and the Commission conducted sensitivity
analysis in its draft decision.
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Option 1
Option 2
Option3
Item
220kV
400kV
Duplex
WKM-PAK
WKM-PAK
OTA-WKM A&B
PV $ 2006 (millions)
Mean capital cost (A)
687
682
737
Mean O&M costs (B)
24
25
21
Mean unserved energy cost (C)
0
0
0
Mean relative loss cost (D)
0
-1
60
Mean terminal benefit (F)
12
13
4
Strategic benefit (G)
0
-5
0
Mean NPV cost
698
688
813
(A+B+C+D-F+G)
Difference v 220kV
-
-10
115
Table 6-2: Ranking of the Transpower proposal and alternatives with the 220 kV
alternative as the reference case.
214 Table 6-3 presents a summary of the sensitivity studies used to confirm the
rankings of the proposal and the alternatives for a variety of changes to key
parameters.
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Option 3
Option 1
Option 2
Difference
Duplex
-$2006 million-
220kV
400kV
400kV-
WKM-PAK
WKM-PAK
OTA-WKM
220kV
A&B
Mean NPV costs
698
688
813
-10
Sensitivity:
$2011
1112
1096
1296
-16
Capital cost +20%
835
824
961
-11
Capital cost -5%
664
654
777
-10
System SRMC
698
687
827
-11
Loss cost +30%
698
687
834
-11
Loss cost -30%
698
689
793
-9
Discount rate 4%
934
883
1159
-51
Discount rate 10%
545
553
602
8
Property escalation 0%
682
680
784
-2
Property escalation 6%
724
697
857
-27
Exchange rate 10 yr average
691
687
807
-4
Hydro/Renewable scenarios - 0
750
722
903
-28
new generation
Reduced demand scenario - 1
714
701
846
-13
new generation
Coal scenario – 2 new
674
674
776
0
generation
Gas scenario - 3 new
629
640
688
11
generation
Gas scenario only, rated up
-
-
-
41
– 6 new gen
40%, 20%, 20%, 20%, 0,2,4,6
-
-
-
2
new gen
New generation prior 2030 only
680
675
793
-5
20 year analysis period
613
634
696
21
Urban sprawl 10km
701
688
813
-13
Upper 50% runs
747
721
882
-26
Lower 50% runs
653
658
753
5
Risk adjusted timing
758
753
839
-5
10% POE Demand path only
769
737
924
-32
Table 6-3: Sensitivity of expected net market cost of the Transpower proposal and
alternatives and expected net market cost difference between the proposal and 220kV
reference case
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215 The sensitivity studies show that the benefit of the proposed option is even
greater under a social discount rate of 4% and for the renewable and hydro
scenarios. The proposal also improves under a lower demand scenario with only
one generator going into the upper North Island area.
216 The proposal is less economic under scenarios with high levels of generation in
the upper North Island (gas scenario with 3 or more new generators).
217 The result is robust to changes in capital cost as all projects are similarly affected.
218 Re-running the GIT calculation tool with the risk adjusted project timing described
in section 7 does not change the ranking of alternatives. Refer to Attachment E
for further details.
6.3.1
Discussion on Options 1 & 2: new line WKM-PAK
219 From a GIT perspective, even though Option 2 passes the GIT, there is very little
separating Option 1: 220 kV and Option 2: 400 kV WKM-PAK (Proposed) given
that the cost estimates are limited to 20-25% accuracy and the number of
assumptions made with respect to costs generally.
220 Given the closeness of the comparison, Transpower believes it is appropriate to
examine the sensitivity studies and the ranges in outcomes that they provide.
Transpower also believes the two projects can be differentiated by considering
non-quantified benefits that are discussed below.
221 Another significant differentiator between these two projects is the requirement in
the 220 kV option for an additional corridor in later years.
222 The maximum ‘corridor capacity’ for the 220 kV option is 1200 MVA compared
with 2700 MVA for the 400 kV proposal. This latent capacity may provide
additional comfort to potential investors that there is a greater likelihood, in the
longer term, for capacity to be readily available from the 400 kV option. The lead
time for establishing substations is of the order of 2 years and designation,
consenting and easement issues are less likely because only substation works
will be required. The 220 kV option will face significantly more challenges in this
area as a new easement will be required.
6.3.2
Discussion of the potential ranges of outcomes
223 The sensitivity studies show there is a range of possible outcomes.
224 In view of the closeness of the results between the proposal and the next best
alternative, the 220 kV Option 1, Transpower has considered other factors to
inform the selection of the preferred alternative.
Demand Analysis
225 The demand analysis using the lower and upper 50% of runs shows that the
range of outcomes can be considered to be in the range of $5M to -$26M. The
GIT analysis was carried out using the 2005 SoO load forecasts and observations
in the 2006 winter were on the high side of the 2005 SoO load forecasts.
Transpower’s view is that there is no basis to assume that future load outcomes
will be on the low side and that 2006 observations suggest outcomes are more
likely on the higher demand side of the range (i.e. more in favour of the proposal).
If demand is in the lower range (<50%), it is likely there will be less generation
and this will have a compensating effect.
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Renewable energy sources
226 The (draft) GPS makes it clear that it is the Government’s intention to facilitate
and promote renewable energy sources
, as per clauses 34A, 87A and 87B. The
range of potential outcomes are for three new thermal generators in Auckland to
zero new generators under the renewables scenario, giving possible outcomes in
the range $11M to -$28M.
227 Further analysis has considered up to six new thermal generators in Auckland
(Refer to Attachment E) which expands the range to approximately $41M to -
$28M. Arguments have been raised about the need for ‘conventional’ generation
to ‘back-up’ intermittent renewable generation (such as wind). Transpower notes
the initiative by Genesis and Contact to seek consent for a potential LNG terminal
in Taranaki.
228 If additional thermal generation is required, as argued, the prospect of all this
generation going into Auckland is unlikely, given the requirement for gas pipeline
capacity into Auckland.
229 Furthermore, unless the HVDC inter-island link is downgraded, an obvious choice
for providing back-up to intermittent renewables is hydro generation, available in
both the South and North Island.
230 Transpower therefore argues that the prospect of many new generators in
Auckland is low and that the higher probability outcome, particularly in the light of
the (draft) GPS, is at the lower end of the thermal generation outcomes in
Auckland.
231 Transpower believes the appropriate range of outcomes thus lies in the range
-$13M to -$28M, representing up to one new thermal generator in Auckland.
Property escalation
232 The property escalation range is from -$2M to -$27M depending on whether
property is escalated at 0% or 6% relative to CPI. The base results use 3%
escalation.
233 The 200 km line route passes through a range of land usage types from rural to
developed. The actual escalation will vary between land usage types with rural
being closer to 0% and developed being closer to 6%.
234 The increasing popularity of ‘lifestyle’ blocks south of Auckland, together with
increasing urbanisation, add weight to a higher escalation rate. Transpower notes
that there is already significant development up to the ’40 year urban boundary’ in
the vicinity of the proposed transition/substation.
235 If the South Auckland urban boundary is revised, as would appear likely,
development further south would necessitate future corridors to terminate further
from Otahuhu or Pakuranga substations. The increased cost of cabling from
these termination points would significantly increase net project costs.
236 Considering the cost of the corridor for the proposal is approximately $80M and
the cost per km of underground cable is in the order of $5-8M/km per circuit, cost
escalation at the higher rates would seem, on average, to be justified.
Discount rates
237 Varying the applicable discount rates shows a range of outcomes between $8M
and -$51M.
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238 Transpower believes the discount rate for long-term investments with an element
of ‘social good’ requires a lower discount rate than the standard 7% used in the
base case. The argument for a discount rate in the vicinity of 4% is supported by
advice from independent consultants15
239 Transpower believes that the adoption of a lower discount rate would favour the
proposal.
6.3.3
Other non-quantified benefits favouring the proposal
240 There are a number of other benefits that Transpower believe additionally favour
the proposal and which if quantified, would be included in the GIT results.
241 They are difficult benefits to defensibly quantify. Work is underway to quantify
these benefits and the results of this work will be advised once available.
242 They are broadly grouped as competition benefits and capacity benefits, further
described below.
Competition benefits:
243 In its draft determination of Transpower’s original 400kV investment proposal16,
the Commission argued that since the 400kV proposal and the alternative
projects provided similar levels of unconstrained transmission capacity,
competition benefits would be equal for each alternative, therefore making it
unnecessary to quantify them as they would net out in the economic analysis.
244 In a recent paper, The Energy Centre17 point out that:
“…this argument is based on the mistaken assumption that the intensity of
competition in an electricity market can be improved by transmission investment
only if an absolute transmission constraint is relieved. Under the Commission’s
reasoning, a transmission line that had 1000MW of unused capacity…would not
generate any additional competition benefits over and above those generated by
a transmission line that…had 1MW of spare capacity…”
245 They go on to show that recent economic research supports an argument that
since the 400kV project provided more actual capacity than the alternatives it
would be expected to generate greater competition benefits.
“The key idea is that a transmission line provides a threat of competition to
generators located in different areas…[provided] the line has sufficient capacity
that generators do not find it profitable to ignore the possibility of output
expansion by a rival…”.
15 “Discount Rate for the Grid Investment Test” Report to Transpower, August 2006, Castalia
Strategic Advisors. Refer to Attachment L
16 “Economic assessment of Transpower’s Auckland 400kV grid investment proposal”, May
2006.
17 “Submission to the Electricity Commission and the Minister of Energy on: Transpower’s
Auckland 400kV investment proposal draft decision”, 22 June 2006
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246 Transpower agrees with The Energy Centre’s analysis and consider that the
same arguments will apply to the Amended Proposal in this Application for
Approval. The Amended Proposal has significantly more thermal capacity than
the alternatives and this capacity can be released at relatively short notice
compared to the alternatives. This becomes particularly noticeable in the years
leading up to the need for a second new 220kV line in the reference case, and
the years leading up to the need for new 220kV lines in the duplexing alternative.
Therefore, Transpower believes the proposal does have a competition benefit
compared to the alternatives.
247 The benefits that arise from such a situation are categorised into two groupings:
• benefits which reduce the overall supply cost of electricity. These arise
because heightened intensity of competition forces generators to become
more efficient operationally.
• benefits which reduce the price of electricity to consumers. These also arise
because of heightened intensity of competition, but are differentiated from the
previously discussed benefits because they are wealth transfers between
generators and consumers and cannot be included in the GIT.
248 Transpower is working to quantify both types of benefit, because even though
only the first can be included in the GIT, the Commission are required under the
GPS to
“…promote and facilitate retail competition…”, hence Transpower would
expect the Commission to take into account information which demonstrates the
extent to which limited competition is affecting consumers.
249 The GIT requires Transpower to estimate the direction and magnitude of non-
quantifiable benefits.
250 Competition benefits accrue in a direction that favours the proposal, because of
the higher latent capacity. Transpower is unable at this stage to quantify the
magnitude of this benefit. Accounting for the competition benefits arising from the
latent capacity is also consistent with the requirements of the (draft) GPS.
Capacity benefits
251 As discussed above, the Amended Proposal has significant amounts of unused
thermal capacity, particularly in the earlier years, compared to the alternatives.
Although there is a cost in investing in such a large line (the initial capital costs of
the Amended Proposal are higher than the alternatives) Transpower believes
there are capacity benefits associated with having large amounts of surplus
capacity, compared to alternatives which provide smaller amounts, or just
sufficient, capacity. These are categorised into three different potential benefits.
The Energy Centre paper18 discusses two aspects of transmission investment
analysis, categorised as capacity benefits:
1) The first relates to the interdependence between transmission and generation
investments. The paper points out that, in general, transmission investments
drive generation investments. Potential investors in generation pay
considerable attention to (expected) decisions on transmission investment
and these decisions
“…influence the profitability of different generation
investments (technology as well as location) differently. More specifically the
signal not to build a new transmission line, will stimulate…generation
investments near Auckland…”. Such an outcome may or may not be
18 “Submission to the Electricity Commission and the Minister of Energy on: Transpower’s
Auckland 400kV investment proposal draft decision”, 22 June 2006
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economic for New Zealand. It will only be economic if building generation
near Auckland is the cheapest option. If building generation in Taranaki (say)
is cheaper, but the possibility of being able to exercise market power, at least
for a short time, leads to a generator building in Auckland instead, then the
outcome is sub-optimal for New Zealand.
Transpower agrees with this assessment and considers that the Amended
Proposal and reference case are similar in this regard and that both have a
capacity benefit over the duplexing alternative until 2020. However, the higher
latent capacity of the proposal favours this option. The duplexing alternative,
which limits transmission capacity into Auckland prior to a new 220kV being
built in approximately 2020, may stimulate (sub-optimal) generation
investment in the Auckland region.
2) The second capacity benefit relates to the impact of uncertainties on
transmission and generation investments. In their draft determination, the
Commission have correctly identified that postponing major transmission
investment decisions creates more time for clarity to emerge with respect to
future generation investment. This is termed transmission option value and if
correctly identified, may be added as a benefit in GIT analysis. The Energy
Centre paper points out however, that creating an option value for
transmission investment may do so at the expense of option value for
generation investment i.e. where options for transmission are kept open,
uncertainties increase for new generation investors, thereby increasing their
risks/costs.
The Amended Proposal has significantly more latent thermal capacity than
the alternatives (two years as opposed to seven years for a new line) and this
capacity can be released at relatively short notice compared to the
alternatives. Whilst this may mean the Amended Proposal has less
transmission option value than the alternatives, it reduces the uncertainty for
generation investors compared to the alternatives and thereby gives a higher
generation option value.
Considering the relative capital intensity of generation and transmission
investments, Transpower believes it is better to provide higher generation
option value through certainty of transmission investment. In this context,
Transpower believes the direction of the benefit favours the proposal.
Transpower has not been able to estimate the size of this benefit at this
stage.
3) The third capacity benefit relates to the flow-on effect to the economy from
having good infrastructure in place. Transpower has a view that “just-in-time”
infrastructure development creates, at the very least, a perception of
uncertainty to potential investors in New Zealand. Castalia was commissioned
to consider an approach for quantifying such effects and their paper is
attached to this application as Attachment N – Foreign Direct Investment
Effects19. Quoting from that paper:
“
Because it is difficult to predict the likely increase in Foreign Direct
Investment (FDI) that the Upgrade will generate, we have cast the proposition
as the following question:
19 At Transpower’s request, Castalia focussed on foreign investment in New Zealand, but it
should be noted that similar arguments could be developed for local investment.
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What increase in investor confidence and FDI would result in the Earlier
Option delivering $100m more welfare than the Later Option (in present value
terms, taking into account only the different effects on investor confidence of
the two options)?
We chose $100m as the order of magnitude of the cost differences being
debated in the Auckland Supply Upgrade.
We find that an increase of about $2.3m in the annual flow of FDI would
generate the additional $100m in welfare. To put this in perspective, the
$2.3m figure represents a 0.09 percent increase in FDI.”
Castalia’s reference to Earlier and Late Options is a reference to the
Commission’s draft determination where a comparison was made between
building a new transmission line in 2010 (Earlier Option), or by using
incremental investments, deferring the new line until 2017 (Later Option).
Castalia go on, in their paper, to acknowledge that there is no way of knowing
what the FDI effect of one transmission investment versus another will be.
“Rather, we think the assessment can be left with the Electricity Commission
and the Government. To decide to save some tens of millions of dollars by
opting for a just-in-time transmission upgrade plan—rather than a plan with
more surplus capacity, decision makers have to be confident that the increase
in FDI from an earlier upgrade will be less than one tenth of one percent.”
Clearly, the Amended Proposal, with its large amount of surplus capacity, will
enable a significantly higher level of investor confidence with respect to
Auckland infrastructure and will therefore encourage higher levels of FDI.
Transpower believes the direction of this benefit favours the proposal,
because of the investor confidence provided by the higher latent capacity than
the 220 kV reference case. Transpower believes that any long term investor
would appreciate the availability of this latent capacity. The discussion above
shows this is a significant benefit for even very small changes in FDI.
6.3.4
Discussion on Option 3: Duplex WKM-OTA A and B
252 This option has high initial costs that offset the initial attraction of a medium-term
remedial measure.
253 The Otahuhu-Whakamaru A and B transmission lines are over 50 years old and
require substantial refurbishment and tower replacement works in order to reliably
support double the conductor weight and increased wind loading.
254 The physical works are $97.7M of the of the total project cost estimate.
255 The property costs for this line are estimated to be $83.0M. Transpower is
satisfied that this is a reasonable estimate and consistent with costs assessed for
options 1 and 2.
256 Even if, in an extreme case, the property costs for this option were considered to
be zero, the GIT analysis shows that the project would still lag options 1 and 2 by
approximately $40M.
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257 Similarly, if the variant discussed in Section 4.4.3 were adopted – using only one
cable into Pakuranga and retaining in service the existing lines – the cost savings
of around $50M would, on its own, be insufficient to warrant adoption of this
variant.
258 A significant cost for this option is attributable to the relatively high losses
incurred on the line. This arises initially in the first ten years prior to the
construction of a new greenfield 220 kV line. During this period, Options 1 and 2
both benefit from having two low-loss circuits delivering energy to the Auckland
environs.
259 Given that losses quadruple when current doubles, the generally higher loading
on all the parallel transmission lines in the initial years, and in later years before a
second 220 kV line is required, accumulate loss costs that prejudice this project
against Options 1 and 2.
260 In addition, the lower latent capacity in the initial years would not provide the
same level of confidence to investors (GPS clause 87G and benefits described in
6.3.3) than would Options 1 and 2.
261 It is also arguable that the lower latent capacity would reduce competitive
pressures in the generation sector and provide less to renewable generation in
central and southern North Island access to upper North Island markets.
262 Further suggestions to reduce cost include the use of high temperature conductor
(HTC) for those components of the Otahuhu-Whakamaru line that would require
easements. This constitutes about one third of the line length, or 70 km, on the
current assumptions for consenting and easements.
263 The use of HTC for one third of the line would increase capital costs by
approximately $31M, being the difference between the cost of duplexed
conventional conductor and simplex HTC. Further increases in cost would be
required to install 13 extra strain towers (at a cost of $1.6M) plus a fund of $5M to
cover the expected increase in Environment Court costs.
264 It is not clear that avoiding duplexing these sections will, of itself, be sufficient to
avoid having to obtain easements. Factors that might trigger a requirement to
obtain easements are not clear but could include consideration of:
• Conductor
Diameter;
• Conductor
Swing;
• Electric and Magnetic Fields;
• Temperature;
and
• Conductor Sag/Tower heights.
265 Even if easements were not required over these sections, Transpower believes at
least $18M would still be required for the removal of structures under the line.
266 The higher losses on these sections of the line would offset cost savings, with an
estimated loss component rising from $60M to approximately $80M, based on
interpolation of the Option 3 and Option 4 loss costs.
267 In addition, the higher reactance of the resulting composite line would increase
the net reactance and therefore the reactive losses. This would require additional
reactive compensation in the Auckland area, increasing costs further.
268 In addition to all the above considerations, Transpower, in section 4.7 has
indicated its concerns about using a relatively new conductor technology, with
limited international application, in precisely those locations of under-build where
concerns of conductor failure are the greatest.
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6.3.5
Discussion on Option 4: Duplex WKM-OTA A and B with HTC
269 This option is virtually identical to Option 3 in the initial years prior to the need for
the next major augmentation.
270 The initial capital cost is affected by the costs of:
• remedial and refurbishment works ($80M);
• the high temperature conductor ($179M); and
• easements
($83M).
271 Comparative results for this option are provided in Table 6.4.
Option 4
Option 1
HTC on
220kV
OTA-WKM
Item
WKM-PAK
A,B,C
2006$ (Millions)
Mean capital cost (A)
687
808
Mean O&M costs (B)
24
20
Mean unserved energy cost (C)
0
0
Mean relative loss cost (D)
0
126
Mean terminal benefit (F)
12
-9
Strategic benefit (G)
0
0
Mean NPV cost
698
963
(A+B+C+D-F+G)
Difference v 220kV
-
265
Table 6-4: Comparative assessment of the non –qualifying alternative Option 4 with the
220 kV alternative as the reference case.
272 Sensitivity results for option 4 are given in Table 6.5.
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Option 1
Option 4
Difference
$2006 million
220kV WKM-
HTC OTA-WKM
HTC-220kV
PAK
A,B,C
Base results
698
963
265
Sensitivity:
$2011
1112
1534
422
Capital cost +20%
835
1124
289
Capital cost -5%
664
922
258
System SRMC
698
1011
313
Loss cost +30%
698
1009
311
Loss cost -30%
698
917
219
Discount rate 4%
934
1438
504
Discount rate 10%
545
694
149
Property escalation 0%
682
941
259
Property escalation 6%
724
997
273
Exchange rate 10 yr average
691
955
264
Hydro/Renewable scenarios - 0
750
1092
342
new generation
Reduced demand scenario - 1
714
1010
296
new generation
Coal scenario – 2 new
674
903
229
generation
Gas scenario - 3 new
629
784
155
generation
New generation prior 2030 only
680
937
257
Urban sprawl 10km
701
963
262
Upper 50% runs
747
1044
297
Lower 50% runs
653
890
237
10%POE demand path only
769
1141
372
Table 6-5: Sensitivity of expected net market cost of the non-qualifying alternative
Option 4 and 220kV reference case
273 Subsequent to 2017, series capacitors will be required on these lines to ensure
sharing between the six parallel 220 kV circuits. This will have the effect of
directing more flow to these HTC circuits, increasing losses accordingly.
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274 The subsequent re-conductoring of the Otahuhu - Whakamaru C line (double
circuit, duplex) would require a similar outlay for the conductors and potentially for
easements and/or cable entries into Otahuhu.
275 As the re-conductoring does not change the line impedance (of the C line), further
series capacitors are required to direct flow onto these circuits, with the flow
increasing the losses markedly on this circuit.
276 The loss costs in Table 6.4 reflect the significantly higher losses incurred in this
option.
277 Transpower believes the high loss costs are contrary to the climate change
imperatives outlined in the (draft) GPS clauses 34A, 87A and 87 B as these
losses all require greater production from thermal generation that could otherwise
be avoided.
278 The higher flows also incur very high reactive losses which necessitate the
installation of additional reactive support for voltage control. This is reflected in
the project capital cost.
279 The conclusion drawn from the economic analysis is that even in the extremely
unlikely case where property costs were zero and the conductor was supplied for
the same cost as conventional conductor, the project would still not be
economically viable.
6.3.6
Comparison with non-transmission alternatives
280 Attachment K shows the non-transmission alternatives are generally not as cost
effective as transmission options 1 and 2.
281 The exception appears to be the case where an existing peak load unit were
moved to the Auckland region from elsewhere in New Zealand (e.g. Whirinaki).
This is because the fixed annual costs of the plant may be treated as zero since
they would have been incurred irrespective of the move.
282 In the case of Whirinaki, for a relocation cost of $30 million this would give a net
market benefit of $39 million. This however needs to be considered in light of the
draft GPS which states that when considering non-transmission alternatives, the
Commission should:
“not consider alternatives which are only likely to proceed if they are
assisted by the government….”
283 A general finding with respect to base load generation is that even if adjusted for
transmission deferral benefits, there are options with lower long run marginal
costs (LRMCs) that are lower and should, in an efficient market, be built before
Auckland base load plant.
284 This finding does not include differences in reliability between transmission and
generation (in favour of transmission).
285 This finding does not necessarily take into consideration all the factors that a
prospective generator may wish to consider before investing. The analysis is
based on costs and benefits that would normally be considered in a centrally
planned power system.
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6.3.7
Impact of the draft GPS
286 The (draft) GPS is discussed in Section 8. The changes proposed by the
Government effectively add weight to the renewable and hydro energy futures. As
such, Transpower believes these sensitivities should be weighted higher than the
coal and gas scenarios. This favours the proposal as the renewable, hydro and
low Auckland generation (low growth) scenarios deliver improved economies over
the 220 kV alternative as illustrated in table 6-3.
287 The(draft) GPS specifies two requirements in relation to diversity:
• [Clause 80] … where practical, the transmission grid should
provide adequate alternative supply routes to larger load centres
having regard to the load which could otherwise be disrupted and
the duration of any disruption; and
• [Clause 88E] … to the extent the Commission considers the
environmental effects of new lines, it should also take into account
any longer term benefits that larger capacity lines may provide by
avoiding multiple smaller lines.
288 Transpower has given effect to these requirements by:
• Specifying Pakuranga as the termination point of the proposal and
alternatives, providing the first stages of a longer term
establishment of an ‘eastern corridor’ to supply Auckland; and
• Adopting high capacity designs for both the proposal and the
alternatives to maximise the corridor utilisation.
289 Transpower recognises the tension between the requirements of (draft) GPS
clauses 80 and 88E in that higher corridor capacity reduces the level of diversity.
That is many low capacity lines provide more diversity than fewer high capacity
lines.
290 Transpower believes in this instance the requirements of clause 88E take
precedence over clause 80 because the current concentration of supplies in one
substation – Otahuhu – and limited corridors, will benefit from having a reliable
alternate supply (corridor and substation) of equivalent rating to the current
supply arrangements. This will balance the supply capability of the two corridors
and ensure at least half of the load can be supplied for a low probability event
causing the failure of a corridor.
291 Transpower considers that in the first stage of the proposal, with operation at
220 kV, there is little difference in the diversity of the 220 kV Option 1 and the
proposal, other than the proposal retains the ability to deliver greater capacity
with a shorter lead time than Option 1.
292 Once converted to 400 kV operation, and well into the analysis period, loss of the
corridor (for example a tower failure causing loss of both circuits) will have a
higher impact than loss of a tower on a 220 kV double circuit line.
293 However, the higher capacity of the 400 kV line also provides a degree of
resilience for the failure of one of the existing 220 kV double circuit lines,
considered a higher probability as the age of these lines would be approaching
80 years.
294 Analysis of this high impact, low probability event is provided in Attachment A
(Diversity into the Upper North Island).
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295 On balance Transpower acknowledges the higher impact of losing a heavily
loaded 400 kV circuit, but believes the impacts can be contained using special
protection systems and having fast response repair strategies in place.
6.3.8
Conclusion of the GIT analysis
296 Transpower has demonstrated that the Amended Proposal satisfies the Grid
Investment Test because:
• as a reliability investment, it maximises the expected net market benefit when
compared with the alternative projects;
• it is robust having regard to the results of a sensitivity analysis; and
• satisfies the intentions outlined in the GPS.
297 Of the three alternatives, Transpower believes the non-quantified benefits
identified in 6.3.3 all act in a direction to favour the proposal and some of these
benefits are potentially very significant.
298 In meeting all of the above criteria, the proposed project satisfies the third criteria
for approval under Rule 13.4.1 that the proposed reliability investment “meets the
requirements of the Grid Investment Test”.
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7
The Amended Proposal is appropriately sequenced and
timed
299 As previously mentioned (section 5), the GIT calculation tool was used to ‘rank’
the alternative projects in order to select the proposed project, in accordance with
rule 13.4.1.3.
300 Once the proposed project is selected, two different methods of determining the
timing of its implementation may be applied:
• the probabilistic method, combining the GRS and GIT; or
• the deterministic method using n-g-1 and a prudent forecast.
7.1 Probabilistic method of determining project timing
301 The GIT calculation tool is used to balance the cost of expected unserved energy
resulting from delaying the proposed project against the deferral benefits. This is
the approach used by the Commission in its draft decision. Details of how this
was applied to the proposed and alternative projects are provided in Attachment
E and H1.
7.2 Deterministic method of determining project timing
302 Power system analysis tools are used to determine the point at which the grid is
no longer able to provide a secure supply in accordance with a predefined
security criteria. Deferral of the project beyond this date may result in unserved
energy. A discussion of the criteria used and its justification is provided in section
6.1.
303 The deterministic method is preferred by Transpower as it aligns with GEIP as
discussed in Section 6.1.
7.3 Grid Development Projects
304 Transpower has undertaken to implement a series of grid development projects in
order to maximise the use of available capacity on the grid. These projects are
regarded as ‘common’ projects, as they are required regardless of which major
project is implemented. The Grid Development projects include:
• Establishment of Ohinewai substation (Huntly East); and
• Thermal upgrade of the 220 kV Otahuhu-Whakamaru A and B lines; and
• Bombay bus split; and
• The reactive power investments in the Upper North Island as approved by the
Commission
305 Each of these projects carries a delivery risk and the dates mentioned are subject
to revision. Late delivery on any of these projects may have a bearing on the
short term and major projects.
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7.4 Short-term
projects
306 In addition to the common projects there are also projects that may be cost-
effective to pursue (e.g. new switching station, transmission line upgrades;
phase-shifting transformers) in the short-term prior to the major upgrade.
Transpower accepts that such cost-effective short-term projects would form part
of the proposed upgrade and alternatives in this application.
307 Some short-term projects may assist in meeting regional demands and delay the
need date for the major upgrade to the core grid but may not be cost-effective to
pursue. These types of projects should be regarded as contingency projects.
308 Short-term projects may assist in meeting regional demand and delay the need
for a major upgrade to the core grid. There are two types of short-term projects:
• Cost-effective (or economic) projects that are justified on the basis that their
cost is lower than the unserved energy that would otherwise occur; and
• Projects that are not cost-effective (ie they would not normally be
implemented) but could be implemented to manage unexpected
(contingency) events.
309 Transpower also accepts that cost-effective short-term projects will not be held
back for risk management purposes, which could result in the need-date for the
major upgrade project being brought forward.
310 The actual timing and final commitment to short-term projects may be subject to
revision in the future as uncertainties around the designation, consenting and
easement risks are resolved or as they impact the need and value of the short-
term projects.
311 Appendix D lists 11 sets of short-term projects that have been considered and
gives:
• A description of the project;
• the improvement in transfer capability if the project is implemented;
• the approximate cost of the project; and
• Transpower’s classification of the project.
312 The amount of deferral available from the short term projects in appendix D takes
into account the impact and need for ON constraint of generation. It then
compares the deferral benefits from each option against its cost. The economic
projects are:
•
Option 5: 110kV phase shifting transformers
•
Option 7: Drury switching station
•
Option 8: Drury switching station + upgrade of OTA-WKM C line
The greatest benefit to cost ratio is from short term project 8.
313 In the case of short term project 8, the theoretical maximum deferral is three
years, however in order to achieve this, Huntly power station must be constrained
on to nearly 100% of its output (1314 MW) along with full output from New
Plymouth and Stratford power stations (320 and 360 MW respectively). This
amount of on-constraint is required by the System Operator to cover for the loss
of a major generating unit and a transmission line (n-g-1). Reliance on this
amount of on-constraint is considered impracticable, especially in light of New
Plymouth power station having a long ‘warm-up’ time, therefore a deferral of three
years is not recommended.
314 A deferral of two years could possibly be achieved using option 8, but it still relies
on near maximum Huntly output however this time without New Plymouth power
station being constrained on.
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315 One year of deferral is possible without New Plymouth and without a major Huntly
unit having to be constrained on. This is considered to be a reasonable condition
in light of the potential market distortions that any amount of on-constraint may
cause.
7.4.1
Arapuni-Pakuranga 110 kV line
316 The proposed route for a new 220 kV or 400 kV transmission corridor into
Auckland follows much of the route of the existing 110 kV Arapuni to Pakuranga
Line (ARI-PAK line).
317 Transpower has advised that the construction of the proposed new lines would
require the retirement of the ARI-PAK line approximately 18 months prior to the
in-service date of the new lines which would effectively bring the need date for
the new lines ahead by up to two years. Analysis presented in Appendix D
indicates that the benefit of retaining the ARI-PAK line is only one year.
318 Various methods of maintaining the ARI-PAK line in-service were suggested as
part of the Commission’s draft decision.
319 It has been suggested that significant capital carrying costs could be saved if
there were a means of keeping the ARI-PAK line in-service or finding alternative
ways of mitigating the effect of their absence though the construction phase of
the new line.
320 Appendix E indicates the deferral benefits that could be captured by keeping the
ARI-PAK line in service. It is only economic to undertake the works required to
keep the line in service if the costs are lower than the deferral benefits.
321 Given that the costs of keeping the ARI-PAK line in service are estimated to be
$35M and the benefits are in the range of $15-$22M, Transpower has concluded
that this project is not economic.
322 There are operational, safety, easement and RMA issues which must be
considered in determining the feasibility of concurrent operation of the ARI-PAK
line during the construction of the new line.
323 These implementation risks are further valid reasons why the ARI-PAK line
retention is neither economic nor practicable in the sense that it would introduce
significant risk and potentially prejudice the major project if delays are incurred
with the retention works.
7.5 Appropriate timing
324 Transpower proposes a two step process in determining project timing, namely
that:
• the first step of the project evaluations should be done based on a system
that reflects the direct system needs (i.e. free of designations, consents and
easements and other delivery risk); and
• the second step is to explicitly and transparently consider such risks in
relation to project timing so that Transpower can adequately manage those
risks.
325 In completing the first step of the timing process, Transpower has calculated the
timing for the direct system need using both the probabilistic and deterministic
approach.
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326 Transpower’s assessment of the capacity of cost-effective short-term projects is
that they could provide a project deferral of up to two years under an ideal
generation dispatch scenario, but only one year for normal dispatch scenarios.
Transpower considers it prudent to allow for one year of deferral.
327 The set of short-term projects selected to provide an economic deferral of the
major project is contained within Option 8 of Appendix D. This option including a
Drury 220 kV switching station and upgrade of the OTA-WKM C line provides
cost effective deferral of the major project by one year as previously mentioned.
7.5.1
Probabilistic approach - Transpower
328 For this approach, Transpower engaged ROAM Consulting to analyse the
unserved energy that could be expected as a result of generation contingencies
in the Auckland region, including Huntly. The results of this analysis are reported
in Attachment H2.
329 Transpower used the unserved energy as a function of peak load from the ROAM
report as an input into the GIT model. The GIT model is discussed in Attachment
E.
330 The major project was moved back one year at a time in the GIT model and the
calculated expected unserved energy was added as a cost. The need-date for
the project was found as the year that minimised the total cost, or equivalently,
gave the optimum balance between deferral benefits and unserved energy cost
331 Attachment H1 indicates the required service date for the major project using this
analytical approach is around 2017.
7.5.2
Probabilistic approach – Electricity Commission
332 The Commission provided an analytical model for an alternative approach to that
adopted by Transpower.
333 The alternative approach considers a similar load probability curve but the
assessment of the unserved energy is extended to consider a wider range of
demand outcomes.
334 The rapid increase in unserved energy with increasing demand results in very
high unserved energy for peak demands. This weights the average unserved
energy and can result in higher levels of expected unserved energy.
335 The timing as set by this alternative approach results in a project need of 2013 –
the same outcome as the deterministic approach discussed below.
336 This result is consistent with the Commission’s finding in their draft decision that
the probabilistic approach yields similar results to the deterministic approach.
7.5.3 Deterministic
analysis
337 This section describes the deterministic analysis used to set the need-date for
the projects based on an n-g-1 criterion and the Commission’s ‘prudent’ forecast,
The approach requires the determination of the n-g-1 capacity of the transmission
system and the consequential demand that could be supported in the Auckland
and Northland areas.
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338 The supportable demand was then compared with the ‘prudent’ forecast. The
need-date is set at the year that supportable demand would be exceeded if the
project were not implemented.
339 Figure 7-1 shows the need-date for the proposal and alternatives using the
deterministic approach, with short term projects included. Details are provided in
Attachment D.
340 Using this analysis, the proposed major project is thus required in 2013.
7.5.4
Conclusion on timing
341 Transpower has concluded that, based on the Commission’s probabilistic
approach and Transpower’s deterministic approach, the appropriate timing for the
proposed major project is 2013.
7.6 Accounting for delivery risk
342 Figure 7-1 below shows the timing of the short-term projects and the major
project as determined by the probabilistic and deterministic approaches. These
dates align with those provide in table 5-1 “System need dates for proposed
investment”.
343 The dates shown in the diagram refer to the required commissioning dates based
on need. Late delivery would result in significant levels of expected unserved
energy, as shown in Attachment H1 and H2..
Short-
Major
term
project
project
2010
2011
2012
2013
Figure 7-1. Project timing based on need but excluding delivery risk
344 The above analysis has considered only the technical need and neither method
has made any allowance for the risk of delays in delivering the project. These
risks include delays due to:
• designations ,consents and / or easements
• project and/or construction issues.
345 Transpower has assessed a range of project delivery scenarios for each of the
four projects. The outcome of this analysis, assuming approval is obtained this
year (2006) is shown in Table 7-1. The supporting analysis is presented in
Attachment C.
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Earliest
Probable
Latest
Project
completion
completion
completion
Base (220 kV)
2011
2012
2014
Proposal (400 kV)
2011
2012
2014
Duplexing
2012
2013
2016
High temperature
2012
2013
2016
conductor
Table 7-1: Potential delivery dates taking account of designation, consenting and
easement risks (assuming project commencement early 2007)
346 The approach taken was to explicitly and transparently recognise delivery risks.
The most appropriate way of doing this is to :
• Work towards an earlier completion date with a view to increasing confidence
that the project will be available by the need-date;
• Adjust, where possible, the delivery date as project risks are avoided or
mitigated to avoid an unnecessarily early delivery date if risk do not transpire.
347 Transpower believes that as this is the first major greenfield transmission project
to be built under the Resource Management Act 1991 it would be prudent to take
a risk averse position regarding delivery risk. In all cases this indicates that a two
year advancement should be applied to the major project need-date.
348 Note that some of the short-term projects described in Appendix D also have
designation, property and easement risks – e.g. requiring a thermal upgrade of
the Whakamaru-Otahuhu ‘C’ line, which could result in issues under the RMA.
349 Using the Commission’s model and approach to determining expected unserved
energy, the consequences of not delivering the major project in 2013 would be of
the order of $32M (Attachment H1 and H2), equivalent to just under two year’s
deferral benefit (Appendix E). A delay beyond 2014 would result in expected
unserved energy rising rapidly to $89M, equivalent to more than 3 years deferral
benefit.
350 This is the first greenfield transmission line built under the RMA and will require
the involvement of 7 councils, two regional councils and over 300 land owners.
Given the lack of precedent for Transpower, the risks of delays are therefore
considered to be high.
351 For both the probabilistic and deterministic approaches, Transpower proposes
that the explicit risk allowance should be to bring forward the need-date for the
various projects. This is shown diagrammatically in figure 7-2 below with a two
year advancement for both the short-term projects and the major project.
352 Transpower considers the proposed approach and resultant timing for the
Amended Proposal to reflect good electricity industry practice and reasonable
and prudent management of risk.
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353 A revised project timing comparison is provided in figure 7-2 below.
Short-
Major
term
project
project
High
expected
unserved
energy
2010
2011
2012
2013
Provision for project
delivery risk
Figure 7-2. Revised project timing diagram – including risk allowance
7.7 Timing of the Proposal
354 The revised timing of the proposal, including the short term projects and
accounting for delivery risk is shown in table 7-2 below.
Proposal Timing
(includes risk
Augmentation
allowance)
Install 250 MVAr static reactive plant at Otahuhu
2009
Decommission the 110 kV ARI-PAK line
2010
Establish Drury switching station
Implement thermal upgrade for Otahuhu-Whakamaru C line
(short term
projects)
Install 100 MVAr static reactive plant at Otahuhu
Establish 220 kV substation adjacent to existing Whakamaru
substation (Whakamaru North)
Cable Transition Station, South Auckland
400 kV double circuit line from Whakamaru to cable transition station in
2011
South Auckland. Circuits operated at 220 kV.
(major projects)
2 x 220 kV cables from transition station to Pakuranga substation
220 kV sub station at Pakuranga
Install 3 x 120 MVA supply transformers at Pakuranga substation
Increase operating voltage of existing 110 kV OTA-PAK line to 220 kV
Table 7-2. Timing of proposal
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8
The Amended Proposal is consistent with wider policy
objectives
355 Transpower notes the application is being submitted within the context of a wider
regulatory framework. As such, points of reference within that wider framework
that can reasonably be assumed to be relevant are:
• The purpose of Section III of Part F of the Electricity Governance Rules;
• The Government Policy Statement on Electricity Governance (GPS); and
• The Commission’s objectives
356 These factors are considered further in the following subsections.
8.1 The purpose of Part F
357 Transpower submits that the following factors are relevant to the Commission’s
consideration of the Amended Proposal:
Would approval of the proposal contribute to this
Purpose of Part F
purpose?
1
“facilitate Transpower’s ability to
Yes
develop and implement long term plans
(including timely securing of land
The proposal is a component of Transpower’s long term
access and resource consents) for
plans.
investment in the grid”
2
“assist participants to identify and
Yes, albeit that any proposal following the Part F
evaluate investments in transmission
process will achieve this.
alternatives”
“facilitate efficient investment in
Yes
generation”
The proposal will provide assurance of releasable
capacity into the Upper North Island from the Lower
North Island and the South Island. This will provide both
capacity and confidence to generation investors,
particularly North Island investors in renewable
generation.
“facilitate any processes pursuant to
Yes, albeit that any proposal following the Part F
Part 4A of the Commerce Act 1986”
process will achieve this.
“enable the cost of approved
Yes, albeit that any proposal following the Part F
investments to be recovered through
process will achieve this.
the transmission pricing methodology
applied in transmission agreements”
Table 8-1. Alignment of Proposal with Part F of the Electricity Governance Rules
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8.2 The
GPS
358 Transpower submits that the Government Policy Statement (GPS) provides
useful context for this Amended Proposal. At the time of submitting this
application, there is an extant 2004 GPS, and a draft 2006 GPS, which places
additional emphasis on for example:
• Facilitating
renewables;
• Resilience against low probability but high impact events
• Diversity
• Facilitating competition
• Early corridor acquisition
• Avoiding multiple low-capacity lines
359 Table 8-2 considers how the proposal and alternatives address these wider policy
issues by commenting on both the extant GPS and August 2006 Draft GPS.
October 2006
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
Renewable Energy
34A
Encouraging the development of renewable
Construction of the proposed project or the 220
energy resources is a key part of the
kV alternative would make the grid more robust
Government’s strategy for managing climate
through the provision of, or ability to provide,
change and long term energy security. To
spare capacity. This is required to better
further this aim the Government’s objectives in
withstand the specific characteristics and
relation to renewable energy, are that:
stresses placed on the system by intermittent
•
generation such as wind power.
Undue barriers to investment in renewables
should be reduced or removed
-
• The efficient uptake of renewable generation
should be promoted and
• The national transmission grid should be
planned in such a way as to facilitate the
potential contribution of renewables to the
electricity system and in a manner that is
consistent with the Government’s climate
change and renewables policies.
Transmission
Background
79
The way in which transmission services are
No change
provided and priced impacts directly and
indirectly on all parts of the electricity industry,
the economy and the environment.
Transmission has strong natural monopoly
characteristics, which makes it important that the
Government sets out its policy expectations as
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
to how transmission services should be provided
and priced and how Transpower should operate.
Poorly designed policies may, for example,
encourage inefficient investment in generation,
which would waste scarce capital resources and
cause unnecessary environmental effects.
Objectives for the provision of transmission services
80
The Government's objectives for the provision of
The Government's objectives for the provision of
transmission services are that:
transmission services are that:
• the services are provided in a manner
• the services are provided in a manner
It is Transpower’s view that the construction of
consistent with the Government's policy
consistent with the Government's policy
the proposed project would improve grid security
objectives for electricity
objectives for electricity and in particular that
and reliability into the upper North Island to a
security of supply should be maintained at a
level consistent with prudent planning standards.
level required by residential, commercial and
As a region, the upper North Island has a
industrial users and the Government’s
significant proportion of the residential as well as
economic development objectives
commercial and industrial customer base in New
Zealand.
• the services should be provided at the
standards of power quality and grid reliability
-
required by grid users and consumers as
determined by the Commission
• the transmission grid should be adequately
The proposal – and Transpower’s wider
resilient against the effects of low probability
development plan in which the proposal sits – is
but high impact events having regard to the
designed to cover, to the extent technically and
-
load which could be disrupted and the
economically feasible, low probability but high
duration of any disruption
impact events. In addition, the flexibility provided
by the eastern corridor, the Otahuhu substation
development and the termination point at
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
Pakuranga will provide flexibility that will:
o
place less load at risk of a major
substation failure; and
o
improve recovery times because
of the ability to transfer loads.
•
The proposal and the 220 kV alternative both
where practical, the transmission grid should
provide alternative supply routes (corridors) to
provide adequate alternative supply routes to Auckland. All three projects considered facilitate
-
larger load centres having regard to the load
a new supply point – Pakuranga- for Auckland.
which could otherwise be disrupted and the
duration of any disruption
•
The proposal and 220 kV alternative both
competition in generation is facilitated and
provide sufficient capacity initially to facilitate
transmission constraints are minimised
competition. The proposal has a slight
advantage in that in later years there is an ability
-
to readily release significant additional capacity
whereas the 220 kV option will require the
construction of a further line along the proposed
or a new corridor.
•
As mentioned above, a strong grid is required to
the transmission grid should be planned and
allow for significant development of wind power
operated in a way which helps achieve the
and other intermittent generation. The proposal
government’s climate change and renewable
is part of a wider plan to upgrade the backbone
energy objectives
-
of the national grid. An anticipated outcome of
this wider upgrade plan is that future renewable
energy projects will be able to be incorporated
into the country’s generation portfolio on a larger
scale than is currently possible.
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
• the efficiency of transmission services
No change
should be continuously improved so as
to produce the services grid users and
consumers want at least cost, and
• the services are priced in a manner that:
No change
o is transparent
No change
o fully reflects their costs including risk
No change
o facilitates nationally efficient supply,
No change
delivery and use of electricity
o promotes efficient investment in
No change
transmission or transmission
alternatives
o promotes nationally efficient use of
No change
transmission services by grid users
and consumers.
•
stakeholders and the public are kept well-
informed about how security of supply is to
-
be maintained throughout the development
and consideration of any grid upgrade plans.
Investment in and maintenance of the transmission network
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
86
As part of its modeling and forecasting work, the
No change
Commission should provide for the development
of statements of opportunities relating to
transmission. These should:
i. incorporate electricity demand and supply
No change
forecasts
ii. enable identification of potential opportunities
No change
for:
o
efficient management of Transpower's
No change
transmission network including
investment in system expansions,
replacements and upgrades
o
transmission alternatives (notably
No change
investment in local generation,
demand-side management, and
distribution network augmentation)
iii. facilitate long term planning for timely
No change
securing of easements and resource
consents
iv. be prepared at least biennially.
No change
87
Transpower should submit grid upgrade plans to
Transpower should
develop and submit grid
Transpower has developed and analysed the
the Commission for approval. The grid upgrade
upgrade plans to the Commission for approval.
options from which the proposal and alternatives
plans should be consistent with statement of
have been derived.
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
opportunity forecasts and demonstrate the
rationale for all expenditure (operation,
maintenance and capital), taking into account
the prescribed reliability standards. The plans
should demonstrate that the proposed
expenditure is required to meet reliability
standards and/or deliver the greatest net benefit
after taking into account transmission
alternatives. The Commission should ensure
that affected parties are fully consulted.
87A
Except where urgency is required for individual
The submission of Transpower’s GUP on 30
projects, any grid upgrade plan submitted by
September 2005, and the submission of this
Transpower should be as comprehensive as
amendment, is consistent with this objective.
possible, ideally covering short, medium and
longer term proposals. This will better enable
consideration of the interrelationships between
projects and the wider synergies from the grid,
-
including facilitating renewables, least-cost
provision of new generation and increased
competition between generators. It will also
enable consideration and approval of proposed
expenditure for the grid as a whole over an
appropriate timeframe (for example, five years)
within a longer term framework.
87B
The grid upgrade plan should also be consistent
The 30 September 2005 GUP, and this
with statement of opportunity forecasts and
amendment, meet with this requirement,
-
wider government energy policy including
including being consistent with the wider
applicable policies on renewable generation and government energy policy, beyond Part F of the
climate change.
EGR’s.
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
87C
Grid upgrade plans should demonstrate the
The 30 September 2005 GUP, and this
rationale for all expenditure (operation,
amendment, are consistent with this requirement
maintenance and capital), taking into account
the prescribed reliability standards and good
industry practice for power system operation.
-
The plans should demonstrate that the
proposed expenditure is required to meet
reliability standards and/or deliver the greatest
net benefit after taking into account
transmission alternatives and government
energy policy requirements.
87D
In the development of grid upgrade plans, the
Transpower, as grid planner, favours the
Government’s objective is that Transpower
Amended Proposal as it is part of a wider plan to
should undertake the detailed planning role
develop the national grid, which is expected to
(including the assessment of transmission
strategically place the grid in a position where it
-
alternatives) and the Commission should
is best able to meet the future challenges of
assess and approve grid upgrade plans that
growth (both demand and in renewables) and
satisfy the required standards and evaluation
uncertainty, while optimising the utility of the
criteria and reject applications that fail them.
assets involved, including transmission
corridors.
87E
The Commission should make available to
From Transpower’s perspective the Interim
Transpower and other stakeholders clear and
Working Phase has contributed significantly to
-
specific criteria on how any grid upgrade plans
meeting this requirement.
in general and any particular plan specifically
will be assessed.
87F
The Commission should ensure that affected
Transpower supports transparency in the
-
parties are fully consulted on grid upgrade plans
transmission planning process.
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
87G
In developing and considering grid upgrade
In Transpower’s view the Amended Proposal
plans, Transpower and the Commission should
will achieve levels of grid security and reliability
seek to maintain business confidence by
in the upper North Island, required to maintain
-
making it clear that adequate security of supply
business and investor confidence in the region.
will be maintained.
The latent capacity of the proposal to meet
projected demands for many years to come
should engender confidence.
88
Where the Commission approves investment by
No change
Transpower has proposed a process for cost
Transpower, the cost of that investment should
recovery as part of its application of the
be recoverable by Transpower in accordance
Amended Proposal, that ensures Transpower
with the pricing methodology determined by the
recovers its full economic cost, while at the
Commission.
same time allowing for monitoring of and
reporting on Transpower’s management of costs
incurred.
Planning ahead
88A
The current pressing need for a number of
A timely decision to approve the proposal, and
major upgrades on the transmission system
the future implementation of Transpower’s wider
reflects, in part, insufficient planning and
strategic plan to develop the national grid of
-
securing of consents (or designations) and land
which this Amended Proposal is a part, will meet
access rights in the past. Government is
the concerns addressed in this point.
concerned to ensure that this situation is not
Transpower’s Annual Planning Report provides
repeated in the future.
clear indications of future augmentation needs.
88B
The Government therefore expects Transpower
A timely decision to approve the proposal will
and the Commission to ensure that Transpower
meet the concerns addressed in this point. Rule
changes to allow corridor designation well in
-
identifies and secures the necessary land
corridors and, to the extent possible, resource
advance of project approval and delivery would
consents (or designations) well in advance of
assist in this regard by providing the basis for a
urgent need. Transpower should be able to
designation and resource consents..
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
recover the reasonable costs of doing so.
88C
This should help the essential process of
A timely decision to approve the proposal will
maintaining stakeholder confidence in ongoing
meet the concerns addressed in this point.
security of electricity supply even if, at times,
Transpower is of the view construction of the
Amended Proposal will minimise future costs,
-
there is some loss of flexibility around
investment choices and some additional cost for
including among other things the costs and risks
electricity consumers.
associated with the acquisition of further
transmission corridors, in maintaining an
adequate level of grid security and reliability.
Environmental effects
88D
Final environmental requirements are
Transpower is of the view that the Amended
determined by consenting authorities under the
Proposal is the best alternative when
Resource Management Act which provides the
considering the trade-offs between cost, grid
reliability, security, and other benefits, and
-
statutory framework for dealing with
environmental effects.
environmental impacts, including impacts on
residential areas. It is recognised that the
proposal is subject to review through the RMA
processes.
88E
To the extent the Commission considers the
The proposal has been designed to optimise the
environmental effects of new lines, it should
trade off between costs, benefits and
also take into account any longer term benefits
environmental impacts, including optimising the
number of transmission corridors required for
-
that larger capacity lines may provide by
avoiding multiple smaller lines.
the grid as a whole, going forward into the
future. Transpower’s proposal only requires one
new overhead line corridor as opposed to two
for the alternatives.
Transmission alternatives
Non-transmission alternatives to transmission
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
89
As part of its consideration of transmission
As part of the consideration of transmission
Transpower has cooperated with the
investments, the Commission should ensure that
investments, the Commission should ensure
Commission to develop generic generation
transmission alternatives are properly
that, in addition to considering transmission
projects as alternatives to transmission
considered to the extent practicable
alternatives, non-transmission alternatives are
investments. These have been assessed and
considered to the extent practicable subject to
compared with the transmission proposal and
the following conditions:.
alternatives. The best of these options,
relocation of Whirinaki to Auckland, is a
government owned generator and is the lowest
•
the Commission should only consider
cost generation option only because of the sunk
alternatives which have a high probability
capital cost of the plant.
of the alternatives proceeding and the
Commission has determined that on-going
security of supply can be maintained if the
alternative is delayed or does not proceed
•
the Commission should not consider
alternatives which are only likely to proceed
if they are assisted by the government or
an agency acting on behalf of the
government unless and until the
government has explicitly authorised or
agreed to provide such assistance.
90
As part of its consideration of transmission
No change
pricing, the Commission should consider
whether there would be net benefits in providing
for a mechanism whereby investments in
transmission alternatives receive payments
reflecting some or all of the value of avoided
transmission investment. This is a complex
subject, and the Commission will need to take
into account, among other things, practicalities,
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Would approval of the proposal contribute to
Government policy statement 2004 (extant)
Government policy statement 2006 (draft)
this purpose?
effects on incentives to invest in alternatives,
and the extent of assurance that grid reliability
standards will be met.
Table 8-2. Alignment of Proposal with Government Policy Statement
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8.3 The
Commission’s
objectives
360 Transpower submits that Commission’s two principal objectives under the
Electricity Act 1992 provides useful context. How approval of the proposal will
contribute to each of these is summarised below:
Commission’s
Would approval of the proposal contribute to this purpose?
objectives
ensure that electricity is
Yes
produced and delivered
to all classes of
Production: the increased capacity of the proposal will enable efficient
consumers in an
competition between generators, leading to productive efficiencies. Over
efficient, fair, reliable,
time, the increased capacity of the proposal will enable efficient
and environmentally
investment in generation, including renewable generation, leading to
sustainable manner
dynamic efficiencies also.
and
Delivery: the increased capacity of the proposal will enable efficient
competition between and dispatch of generation, leading to allocative
efficiencies.
Efficiency: the proposal will provide the efficiencies noted above, reduce
transmission losses, and is the most economic means of delivering
required reliability, as measured by the GIT.
Fairness: the increased capacity of the proposal will avoid tilting the
“level playing field” towards particular producers or consumers.
Reliability: the proposal will significantly increase reliability of electricity
supply for consumers in the Upper North Island.
Environmental sustainability: the increased capacity of the proposal
will:
enable more efficient dispatch of existing renewable energy;
reduce transmission losses;
enable greater investment in renewable generation in the Lower North Island and
South Island;
In consequence, reduce greenhouse gas emissions relative to alternatives; and
Minimise the requirement for additional transmission corridors into the Upper North
Island over time.
promote and facilitate
Yes, albeit that any proposal following the Part F process will achieve this.
the efficient use of
electricity.
Table 8-3. Alignment of Proposal with the Commissions
objectives
361 Transpower considers that the Amended Proposal is consistent with wider policy
objectives and hence is likely to satisfy the Commission’s exercise of any
discretion required in approving the proposal.
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9 Recommendation
362 It is recommended that the Commission approve the Amended Proposal on the
grounds that it:
• complies with the Rules;
• meets the GRS;
• passes the GIT; and
• is consistent with GEIP.
Further, it is the project that is most aligned with the draft changes proposed to the
GPS, particularly with respect to an emphasis on renewable generation, provision of
diversity of supply to Auckland and minimisation of the number of corridors required
for transmission.
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Appendix A Glossary of Terms
Term
Description
AIS
Air
Insulated
Switchgear
Alternative Project
Projects that are reasonable to consider as alternatives to the
proposed investment in applying the Grid Investment Test (GIT), in
accordance with rule 19, Schedule F4, Part F Section III,
Electricity Governance Rules (EGRs).
Amended Proposal
The proposal, for a new line between Auckland and Whakamaru,
which is outlined in this application for approval, dated 30
September 2006. (the “North Island Grid Upgrade project”).
North Island Grid
The project, for a new line between Auckland and Whakamaru,
Upgrade Project
which is outlined in this application for approval, dated 30
September 2006 (the “Amended Proposal”).
Commission
The Commission, a Crown entity set up under the Electricity Act to
oversee New Zealand’s electricity industry and markets.
deterministic limb of the
The deterministic limb of the GRS defines that the grid satisfies
GRS
the grid reliability standards if, with all assets that are reasonably
expected to be in service, the power system would remain in a
satisfactory state during and following any single credible
contingency event occurring on the core grid. (Refer rule 4.2,
Schedule F3, Part F Section III, Electricity Governance Rules
(EGRs)).
Draft Decision
The Commission’s consultation paper explaining its draft decision
on the Original 400 kV Project, dated 27 April 2006.
economic investment
Investments in the grid that can be justified on the basis of the
Grid Investment Test under section III of part F, Electricity
Governance Rules (EGRs), and are not reliability investments.
EGRs
Electricity
Governance
Rule
s. In the context of this document, it
generally refers to Part F Transport, Section III Grid Upgrade and
Investments, 16 February 2006.
expected project costs
Expected project costs (or expected costs) represent the
estimated (P50) cost plus a contingency for scope accuracy.
Scope accuracy allows for unexpected variations in the design
scope and a standard allowance, based on experience, for items
not considered in the design.
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expected unserved
A forecast of the aggregate amount by which the demand for
energy
electricity exceeds the supply of electricity at each grid exit point
as a result of likely planned or unplanned outages of primary
transmission equipment.
GEIP
Good
Electricity
Industry
Practice. Refer section 6.1.2 of this
document.
GIS
Gas
Insulated
Switchgear
GIT
Grid
Investment
Test. A test for reliability investments and
economic investments in the grid developed in accordance with
rule 6 of section III of Part F, Electricity Governance Rules
(EGRs). The specific rules defining the Grid Investment test, as
developed according to the process in rule 6 of section III, are set
out in Schedule F4 of section III of Part F.
GPS
Government
Policy
Statement on Electricity Governance. Refer
section 8.2 of this document.
GRS
Grid
Reliability
Standards. Standards for reliability of the grid
developed in accordance with rule 4 of section III of part F,
Electricity Governance Rules (EGRs), including variations, but
does not include interim grid reliability standards. The standards
themselves as currently developed are detailed in rule 4 of
Schedule F3, section III of Part F.
GUP
Grid
Upgrade
Plan. A plan for grid expansions, replacements and
upgrades, developed in accordance with rule 12 of section III of
part F, Electricity Governance Rules (EGRs).
HTC
High
Temperature
Conductor.
A type of overhead transmission line conductor that is capable of
sustained operation up to temperatures around 200 degrees
Celsius
HVDC Upgrade Project
The proposal to upgrade the HVDC inter-island link between
Benmore in the South Island and Haywards in the North Island, as
detailed in Volume III of the Original GUP, submitted to the
Commission on 30 September 2005.
LRMC
Long Run Marginal Cost
modelled projects
Transmission augmentation projects and non-transmission
projects, other than the proposed investment and alternative
projects, which are likely to occur in a market scenario, are
reasonably expected to occur in that market development scenario
within the time horizon for assessment of the market benefits and
costs of the proposed investment and alternative projects, and the
likelihood, nature and timing of which will be affected by whether
the proposed investment or any alternative project proceeds.
October 2006
© Transpower 2006
Page 86 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
N-G-1
System security standard which is achieved when the power
system remains in a satisfactory state during and following any
single credible contingency event occurring on the core grid
(defined as N-1 security standard), whether Otahuhu ‘C’ generator
is in or out of service.
Original GUP
Transpower’s first GUP, submitted to the Commission on 30
September 2005, containing a number of projects including the
Original 400 kV Project and the HVDC Upgrade Project.
Original 400 kV Project
The original proposal to build a 400 kV line between Otahuhu and
Whakamaru, as detailed in Volume II of the Original GUP,
submitted to the Commission on 30 September 2005.
probabilistic limb of the
The probabilistic limb of the GRS defines that the grid satisfies the
GRS
grid reliability standards if the power system is reasonably
expected to achieve a level of reliability at or above the level that
would be achieved if all economic reliability investments were to
be implemented.
reliability investment
Investments by Transpower in the grid, or alternative
arrangements by Transpower, the primary effect of which is, or
would be, to reduce expected unserved energy.
Transition station
A site where the transition is made from an over-head
transmission line to underground cables.
Transpower
Transpower New Zealand Limited, owner and operator of New
Zealand’s high-voltage electricity network (the national grid).
UNI or Upper North Island Includes the Auckland and Northland regions. The Auckland
region is the area bordered by and including Bombay 110 kV
Substation in the south, and Penrose 220 kV Substation and
Mount Roskill 110 kV Substation in the north. The Northland
region covers the area north of and including Hepburn Road 110
kV Substation.
October 2006
© Transpower 2006
Page 87 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Appendix B Cross Reference with September 2005 GUP
If 400 kV GUP,
If yes or in part,
Part of 400 kV
Section of September
has it been
which sections
GUP or HVDC
2005 GUP
superseded by
of this
GUP?
this application?
application?
Volume 1
Executive Summary
Section 1
Both
Part
Executive
Summary
Sections 2 to 6
Both
No
-
Section 7
400 kV
All
Executive
Summary
Section 8
HVDC
No
-
Section 9
Both
Part
Executive
Summary
Comprehensive Plan
HVDC
No
-
for Asset Management
and Operation of the
Grid
Contracted
HVDC
No
-
Investments
Volume 2
Executive Summary
and Introduction
Section 1
400 kV
Part
Section 1
Section 2
400 kV
All
Section 2
Section 3
400 kV
No
Section 3
Section 4
Section 4
400 kV
Part
Section 5.1
Section 5
400 kV
All
Section 7
Section 6
400 kV
Part
Section 3
Section 7
400 kV
No
Section 4
Section 8
400 kV
All
Section 5
Section 9
400 kV
All
Section 5
Section 10
400 kV
No
-
October 2006
© Transpower 2006
Page 88 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
If 400 kV GUP,
If yes or in part,
Part of 400 kV
Section of September
has it been
which sections
GUP or HVDC
2005 GUP
superseded by
of this
GUP?
this application?
application?
Appendix A
400 kV
All
Attachments
Part 1
Section 1
400 kV
Part
Section 5
Section 2
400 kV
Section 2.1
400 kV
All
Section 5
Section 2.2
400 kV
Part
Section 5
Section 2.3
400 kV
Part
Section 5
Section 2.4
400 kV
Part
Section 5
Section 3
400 kV
No
-
Section 3.1
400 kV
No
-
Section 3.2
400 kV
No
-
Section 3.3
400 kV
No
-
Section 3.4
400 kV
Part
Section 2.4
Section 3.5
400 kV
All
Section 7
Appendix 1A
400 kV
All
Section 5
Appendix 1B
400 kV
No
-
Appendix 1C
400 kV
All
Section 5
Appendix 1D
400 kV
All
Section 7
Part 2
Section 1
400 kV
All
Section 3
Section 2
400 kV
All
Section 3
Section 3
400 kV
All
Section 6
Section 4
400 kV
All
Section 6
Section 5
400 kV
Part
Attachment D
Section 6
400 kV
Part
Attachment D
Section 7
400 kV
All
Section 7
Appendix IIA
400 kV
All
Attachment D
Appendix IIB
400 kV
No
Attachment D
Appendix IIC
400 kV
All
Section 5
Appendix IID
400 kV
No
-
October 2006
© Transpower 2006
Page 89 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
If 400 kV GUP,
If yes or in part,
Part of 400 kV
Section of September
has it been
which sections
GUP or HVDC
2005 GUP
superseded by
of this
GUP?
this application?
application?
Part 3
Section 1
400 kV
No
-
Section 2
400 kV
Part
Section 3
Section 3
400 kV
No
-
Section 4, 4.1, 4.2
400 kV
No
-
Section 4.3
400 kV
All
Section 4
Attachment D
Section 4.4
400 kV
Part
Section 6
Section 4.5
400 kV
All
Section 5
Section 6
Attachment D
Section 4.6
400 kV
No
-
Section 4.7
400 kV
No
-
Section 4.8
400 kV
No
-
Section 4.9
400 kV
No
-
Section 4.10
400 kV
No
-
Section 4.11
400 kV
No
-
Section 4.12
400 kV
No
-
Section 4.13
400 kV
Part
Section 6
Section 5
400 kV
Part
Section 6
Appendix IIIA
400 kV
No
-
Appendix IIIB
400 kV
All
Section 7
Appendix D
Part 4
400 kV
All
Section 6
Appendix E
Attachments
Part 5
400 kV
All
Section 5
Appendix C
Supporting
Documents
1. Request for
400 kV
No
-
Information
October 2006
© Transpower 2006
Page 90 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
If 400 kV GUP,
If yes or in part,
Part of 400 kV
Section of September
has it been
which sections
GUP or HVDC
2005 GUP
superseded by
of this
GUP?
this application?
application?
2. Grid development
400 kV
All
Attachment D
Plan – 400 kV – Part 1
3. Grid development
400 kV
All
Attachment D
Plan – 400 kV – Part 2
4. Grid development
400 kV
All
Attachment D
Plan – 2200 kV – Part 1
5. Grid development
400 kV
All
Attachment D
Plan – 220 kV – Part 2
6. Main Transmission
400 kV
Part
Section 6
System Planning
Criteria
7. Planning
400 kV
All
Section 6
Assumptions – Demand
Attachment D
and generation
forecasting
8. Security of supply
400 kV
No
-
into Upper North Island
– Comparison of High
Voltage Direct Current
and High Voltage
Alternating Current Grid
Upgrade Alternatives
9. 300/400 kV
400 kV
No
-
Transmission Line
Upgrade Study
10. Monte Carlo
400 kV
No
-
Analysis of Auckland
Area thermal Plant
Availability
11. Comparison of
400 kV
No
-
reliability of 400 kV
underground cable with
an overhead line for a
200 km circuit
12. peer review of
400 kV
No
-
choice of voltage for
development of the
New Zealand Grid
13. Security of supply
400 kV
All
Attachment D
into Auckland – review
of system capacity
limitations
14. Methodology to
400 kV
All
Attachments
calculate lower bound
of competition benefits
October 2006
© Transpower 2006
Page 91 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
If 400 kV GUP,
If yes or in part,
Part of 400 kV
Section of September
has it been
which sections
GUP or HVDC
2005 GUP
superseded by
of this
GUP?
this application?
application?
Volume 3
HVDC
No
-
Volume 4
Grid Development
No
-
Proposals
October 2006
© Transpower 2006
Page 92 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Appendix C Cost breakdowns of alternative projects
Option 1: 220 kV into Pakuranga and Otahuhu
Total -Expected
Year
Augmentation
Cost
($ ,000)
2009 350 MVAR Static compensation
9,185
Upgrade OTA-WKM C
4,615
Decommission 110kV ARI-PAK Line
5,032
2010 Drury Switching Station
21,227
Drury Switching Station - Lines
2,047
220kV Line (2 Chukar @ 75C) WKM-ORM
277,068
WHN 220 kV Substation
10,688
WKM Subs Work
3,807
OTA Subs Work
5,242
OTA Enabling Work
3,417
2012 ORM Cable Termination Station
10,755
2x220kV cables ORM-PAK
117,888
220kV Sub Station at PAK
54,231
Shift existing OTA-PAK 110kV circuits to operate at 220kV
688
1st PAK-PEN cable
61,159
PEN GIS Sub
40,033
Reconductor ARI-HAM 1&2 to Nitrogen 75C conductor
12,324
2013 BOB Interconnector
9,479
100 MVAr Static compensation
4,297
ORM Civil Works
8,532
100 MVAr Dynamic compensation
25,159
2017 2nd PAK-PEN cable
61,159
PAK Subs Work
6,866
PEN Subs Work
3,271
2019 100MVAR Static compensation
4,282
110kV OTA-WIR cable; close the WIR bus breaker
35,223
50% series compensation on the ORM-WKM 1&2 ccts
42,021
Switching station at ORM
12,478
2021 One ORM-OTA 220kV cable
69,018
1st OTA-PEN cable
60,949
PEN Subs Work
3,271
OTA Subs Work
6,122
2022 200 MVAR Static compensation
6,541
2nd ORM-OTA Cable
67,916
2024 OTA Subs Work
779
ORM Subs Work
1,747
100 Mvar Static compensation-
4,277
2026 Series current limit reactor - 20 Ohm
18,874
2027 100 MVAR Dynamic compensation
25,164
100 MVAR Static compensation (HLY)
4,277
2029 250 MVAR Static compensation (OTA)
7,422
2nd 220kV Double Circuit between WKM-ORM
262,782
WHN Subs work
4,386
2031 ORM Subs Work
4,318
1st 220kV cable between SAD-PAK
107,555
PAK Subs Work
610
Continued next page
October 2006
© Transpower 2006
Page 93 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
2nd OTA-PEN cable
60,949
2032 PEN Subs Work
3,271
OTA Subs Work
1,444
2035 250 MVAR Static compensation
7,422
2036 PST on ARI-BOB
9,318
1st cable SAD-OTA Cable
96,485
2037 ORM Subs Work
2,381
OTA Subs Work
6,639
2038 150 MVAR Static compensation
5,535
2040 Series Compensate WKM-ORM 3&4 circuits by 50%.
42,016
2042 400 MVAR Static compensation
10,698
Option 1 - 220 kV into Pakuranga and Otahuhu
October 2006
© Transpower 2006
Page 94 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Option 2: 220 – 400 kV Staged to Pakuranga (Proposed Investment)
Total -
Expected
Year
Augmentation
Cost
($ ,000)
2009
350 MVAR Static compensation
9,088
Uprate HLE-HAM-WKM section of OTA-WKM C line to twin Goat @ 80C
4,573
Decommission 110kV ARI-PAK Line
4,979
2010
Drury Switching Station
21,227
Drury Switching Station - Lines
2,047
2x400kV WKM-ORM ccts operated at 220kV
335,219
WHN 220 kV Substation
10,578
WKM Sub work
3,770
OTA Enabling Work
3,381
OTA Subs Work
5,192
2012
2x220kV ORM-PAK cables
116,700
Cable Termination at ORM
10,719
220kV substation at PAK
57,233
Convert OTA-PAK 110kV ccts to 220kV
680
1st PAK-PEN cable
60,529
PEN GIS
39,615
2013
Reconductor ARI-HAM 1&2 to Nitrogen 75C conductor
12,217
BOB Interconnector
9,380
2015
100 MVAr Static compensation
4,232
ORM Civil Works
9,092
100 MVAr Dynamic compensation
24,896
2017
2nd PAK-PEN cable
60,529
PAK Subs Work
1,115
PEN Subs Work
3,237
2019
100MVAR Static compensation
4,232
1x220kV ORM-OTA cable
68,329
ORM Subs Work
13,305
2x55% compensation on WKM-ORM ccts
45,684
2021
Install 110kV OTA-WIR cable - close the WIR bus breaker
34,855
1x220kV PEN-OTA cable
60,316
PEN Subs Work
3,237
OTA Subs Work
6,058
2022
200 MVAR Static compensation
6,473
100 MVAr Dynamic compensation
24,896
2nd 220kV OTA-ORM cable
67,239
2023
OTA Subs Work
771
ORM Subs Work
1,724
2026
100 Mvar Static compensation
4,232
2027
150 MVAR Static compensation -reactive plan of 25/9
5,477
2028
Install 20 Ohm reactor on OTA-WKM A&B line
18,672
ORM Civil Works
10,391
2029
100 MVAR Static compensation
4,232
Continued next page
October 2006
© Transpower 2006
Page 95 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
2030
300 MVAR Dynamic compensation
48,179
150 MVAR Static compensation
5,477
2031
Install cable cooling ORM-PAK cables
8,465
400kV sub at WKM
112,295
400kV sub at ORM
115,690
2033
2nd PEN-OTA cable
60,316
PEN Subs Work
3,237
Install cable cooling ORM-OTA cables
8,465
2037
PST on ARI-BOB
9,221
2040
300 MVAR Static compensation
8,216
2042
300 MVAR Static compensation
8,216
Option 2: 220 – 400 kV Staged to Pakuranga (Proposed Investment)
October 2006
© Transpower 2006
Page 96 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Option 3: Duplexing of Whakamaru – Otahuhu A&B
Total - Expected
Year
Augmentation
Cost
($ ,000)
300 MVAR Static compensation
8,290
2009
100 MVAR Dynamic compensation
25,123
BOB Interconnector
9,465
2010
Drury Switching Station
21,227
Drury Switching Station - Lines
2,047
Uprate HLE-HAM-WKM section of OTA-WKM C line to
2011
4,473
2xGoat 80C
PAK 220kV sub station
58,242
Convert existing OTA-PAK 110kV to 220kV
687
OTA Enabling Work
3,412
2012
OTA Subs Work
4,208
1st PAK-PEN cables
61,071
PEN GIS Sub
39,965
Duplex OTA-WKM A&B ccts, deviate line from Sth
221,666
2014
Auckland to PAK
PAK Subs Work
2,247
South Auck Sub
3,357
2015
Redoubt Rd - PAK cables
136,488
100 MVAR Static compensation
4,271
Second PAK-PEN cable
61,071
PAK Subs Work
6,856
2016
PEN Subs Work
3,326
200 MVAR Static compensation
6,537
Reconductor ARI-HAM 1&c ccts to Nitrogen 75C
12,309
2017
Bussing of OTA-WKM A&B lines at HLE
10,541
OTA-WIR 110kV Cable
35,172
2019
110kV ARI-PAK line decommissioned
5,025
220kV D/C WKM-ORM line (twin Chukar 75C)
274,791
WKM Subs Work
2,865
2x220kV cables from ORM-PAK
146,655
2020
PAK Subs Work
609
3rd PAK-PEN cable
61,071
PEN Subs Work
3,266
Cable transition at ORM
10,600
200 MVAR Static compensation
6,532
2025
PST on ARI-BOB
9,305
2027
100 MVAR Static compensation
4,271
2029
250 MVAR Static compensation
7,411
50% Series Compensation on ORM-WKM 1&2 ccts
41,960
Switching Station at ORM
15,898
2031
1st and 2nd ORM-OTA cables
128,974
OTA Subs work
7,984
2033
50 MVAR Dynamic compensation
16,581
Continued next page
October 2006
© Transpower 2006
Page 97 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
220kV Double Circuit between WKM-Sth AKL
272,882
WKM Subs Work
2,609
ORM Subs Work
4,488
2035
1st OTA-PEN cable
60,862
OTA Subs work
7,233
PEN Subs Work
3,266
3rd OTA-Sth Akl cable
106,213
2042
450 MVAR Static compensation
10,682
Option 3: Duplexing of Whakamaru – Otahuhu A&B
October 2006
© Transpower 2006
Page 98 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Option 4: High Temperature Conductor
Total –
Year
Augmentation
Expected Cost
($ ,000)
250 MVAr static compensation
7,405
2009 100 MVAr Dynamic compensation
24,840
2010 BOB interconnector
9,359
Drury Switching Station
21,227
Drury Switching Station - Lines
2,047
2011 Thermal Uprating of sections of OTA_WKM C south of
4,564
HLE with Goat 80 C
150 Mvar static compensation
5,047
PAK 220kV substation
57,105
3x120MVA supply transformers at PAK
2012 1st PAK-PEN cable
60,394
Convert existing 110kV OTA-PAK circuits to 220kV
679
operation
OTA-WKM A and B lines - HTC Duplex
Disconnect OTA-WKM A and B sections between SAK
and OTA
436,225
2014 OTA-WKM A and B lines redirected from SAK to PAK with
1 cable per line
SAK Cable transition station
3,417
2x220 cable SAK-PAK
135,001
2015 Second PAK-PEN cable
60,394
Reconducting ARI-HAM 1 and 2 circuits to Nitrogen at 75C
12,194
2016
100 MVAr static compensation
4,274
2017 OTA-WKM A and B lines 40% Series Capacitance
45,766
110kV cable from OTA to WIR
34,776
2019 Switching station at SAD
13,275
150 Mvar static compensation
5,451
2021 200 Mvar static compensation
6,477
2022 350 Mvar static compensation
9,063
200 Mvar static compensation
6,477
OTA_WKM C – Duplex HTC (all sections but HLE to
275,388
HAM)
OTA-WKM C installed with 25% series capacitance on
2023 OTA-HLE, and HLE-WKM sections and 30% series
80,730
capacitance on HAM-WKM section.
OTA_WKM A and B bussed at HLE
10,461
1st Cable from OTA to PEN
60,181
2025 PST on ARI-BOB
9,305
2027 450 MVAr static compensation
10,537
Decommission ARI_PAK 110kV line
4,968
2028 1 Ohm series reactor on OTA_SAK bonded pair
2,484
Construction new 2 duplex Chukar circuits from WKM to
2029
272,637
ORM
2030 2nd Cable from OTA to PEN
60,281
Continued next page
October 2006
© Transpower 2006
Page 99 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Cable transition Station at ORM
10,712
2032 New cable from ORM to OTA
68,183
2035 150 Mvar static compensation
5,451
2nd cable from ORM to OTA
68,183
2039 450 MVAr static compensation
10,537
150 Mvar dynamic compensation
31,050
30% series compensation on ORM_WKM circuits
45,581
2040 3rd Cable from PAK to PEN
60,394
250 MVAr Dynamic compensation
43,470
2041 500 Mvar static compensation
11,178
Option 4: High Temperature Conductor
October 2006
© Transpower 2006
Page 100 of 106
Appendix D Short Term Augmentation Projects
Assumptions:
•
• 2010 High demand used as base and the loads scaled to obtain transfer limit (Huntly Generation re-dispatched to get maximum limit)
•
• Arapuni Generation dispatch at180 MW
•
• Huntly East (Ohinewai) switching station commissioned
•
• OTA-WKM A&B lines thermally upgraded to 75 degrees
•
• HVDC dispatch at 1400 MW
•
• PSTs set to have 95% flow post contingency where possible on 110 kV circuits out of ARI, phase shift range +/-30°
•
• PSTs set to have 100% flow post contingency on 220 kV circuits
•
• Transfer Limits quoted are approximate values and the accuracy may vary slightly due to the numerical algorithms used
Deferral
Deferral Benefit
ARI-PAK
ARI-PAK
Cost
benefit
benefit
- Cost
in
out
($m) 2
No
Description
Comment
(years) 3
($m) 4
($m)
Upper North Island
Transfer Capacity(MW)
1
Base
2668
2510*
By itself, this project has marginal
2
PSTs on HLE-OTA 1 & 2 Circuits
Minimal
Minimal
impact on the transfer capacity
-
0
-
No benefit
Thermal upgrade of OTA-WKM C
By itself, this project has marginal
3
Minimal
Minimal
line upgrade to 80 deg
impact on the transfer capacity.
-
0
-
No benefit
700 MVA PSTs required (Phase shift
PSTs on HLE-OTA 1 & 2 + OTA-
4
2753*
2667*
requirement to be ascertained).
64.6
1
31.9
-32.7
WKM C line upgrade.
Lower HVDC dispatch is likely to
October 2006
© Transpower 2006
Page 101 of 106
NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
Deferral
Deferral Benefit
ARI-PAK
ARI-PAK
Cost
benefit
benefit
- Cost
in
out
($m) 2
(years) 3
($m) 4
($m)
reduce the transfer limit, but is not
quantified.
With ARI-PAK in the circuits into ARI
from the south particularly KIN-LFD
PSTs on ARI-HAM, ARI-BOB AND
will overload for a HAM-WKM
5
ARI-PAK+OTA-WKM C line
2711
2618
outage. Overloading (up to approx
32.8
1
31.9
-0.9
upgrade
165%) as far back as TRK ICTs, no
overloading without ARI-PAK in
service
With ARI-PAK in the circuits into ARI
from the south particularly KIN-LFD
Re-conductoring of HAM-BOB
will overload for a HAM-WKM
6
circuits+PSTs+OTA-WKM C line
2707
2623
outage. Overloading (up to approx
57.2
1
31.9
-25.3
upgrade
165%) as far back as TRK ICTs, no
overloading without ARI-PAK in
service
Increases transfer from Taranaki and
Huntly However, if the generation
south of Whakamaru is replaced from
7
Drury switching station
2665*
2659*
the Central North Island generation
23.3
1
31.9
+ 8.6
then the transfer limit drops
substantially. Low Huntly generation
will also have a similar effect,
October 2006
© Transpower2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
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Deferral
Deferral Benefit
ARI-PAK
ARI-PAK
Cost
benefit
benefit
- Cost
in
out
($m) 2
(years) 3
($m) 4
($m)
Increases transfer from Taranaki and
Huntly as well as from Whakamaru.
However, if the generation south of
Drury switching station+ OTA-WKM
31.9 to
+ 4.0 to
8
2764*
2736 1
Whakamaru is replaced from the
27.9
1 to 2 5
C line upgrade
Central North Island generation then
61.7
+ 33.8
the transfer limit is likely to reduce.
The 110 kV circuits between Kinleith
Re-conductoring of ARI-PAK+PST
and Tarukenga and inter connector
9
on ARI-PAK +OTA-WKM C line
2751
-
-
0
-
No benefit
at Tarukenga overload up to approx
upgrade
160% and needs augmentation
The 110 kV circuits between Kinleith
OTA-WKM C line upgrade, Drury
and Tarukenga and inter connector
switching station, Recondutor ARI-
10
2805
2724
at Tarukenga overload up to approx
Over 80
1
31.9
< - 48.1
PAK and HAM-BOB, PSTs on all
200%, where ARI-PAK is in service
110 kV circuits north of ARI
and needs augmentation
OTA-WKM C line upgrade, Drury
The 110 kV circuits between Kinleith
switching station, Recondutor ARI-
and Tarukenga and inter connector
11 PAK and HAM-BOB, PSTs on all
2879
2803
at Tarukenga overload up to approx
Over 140
2
61.7
< - 78.3
110 kV circuits north of ARI, PSTs
205%, where ARI-PAK is in service
on HLE-OTA circuits
and needs augmentation
Notes:
1. BOB-WIR-OTA circuit breakers are open at BOB to prevent overloading on the HAM-BOB circuits reducing the transfer limit
2. Costs are provided only for those options that provide more than one year of deferment of the major project.
3. Deferment is assessed only for options with ARI-PAK out. Years of deferment is assessed on the basis of likely generation dispatch scenarios.
4. Refer to Appendix D of this report “Assessment of the value of deferring investments”
5. Option 8 provides at least one year of deferral, with possibly more under favourable generation dispatch scenarios. It also provides benefit during summer
peak periods when Huntly generation is often constrained down.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
Application for Approval - 20 October 2006
Appendix E Assessment of the value of deferring investments
Delaying the need for an investment may have a benefit if the cost of delaying the
investment is less than the deferral benefit.
The value of money to be spent now is higher than money that can be spent later as
you could alternatively invest the money (e.g. in governmental bonds – considered a
risk free investment) and get a return. Thus, the later an investment is made, the
more other benefits (such as return of investments) could have been achieved in the
meantime. Therefore, money spend in years to come are lowered by a discount rate
to adjust for the benefits the capital can provide in the meantime. This is the origin of
the deferral benefit.
The deferral benefit arises from applying the discount rate on the given investment
for a longer period of time. For example, if using a discount rate of 7%, delaying an
investment by one year will cause the present value of the costs to be lowered by
1/1.07 = 93.4%. For an investment with a present value of $100 million being
delayed a year, the deferral benefit would then be $6.6 million.
In the context of the Auckland Transmission Upgrade proposal, two types of deferral
are of interest. They are explained below.
Deferral of part of the investment
In the economic analysis of the transmission alternatives, several short term options
(see Appendix D) for deferring the need of the first major part of the proposed
investment one or two years are analysed.
The analysis is based on the year 2010 – i.e. the project need date in 2012 brought
forward two years to reduce risks. The costs of those options are to compared with
the deferral benefits, which are:
400 kV in 2010
Defer 1 year
Defer 2 years
Benefits in $million 2006
31.9
61.8
Table E-1. Project deferral benefits
The values arise from delaying the investments from the table below, which are all
due in 2010 if no deferral projects are committed.
Description
2x400kV WKM-ORM ccts operated at 220kV
WHN 220 kV substation
WKN Sub work
OTA Enabling Work
OTA Sub Work
2x220kV ORM-PAK cables
Cable Termination at ORM
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
220kV substation at PAK*
Convert OTA-PAK 110kV ccts to 220kV*
1st PAK-PEN cable*
PEN GIS*
* These projects are needed in 2012 at latest for the strengthening of the across harbour capacity.
Hence, the can only be deferred two years.
Table E-2. Deferral components
The costs of those sum up to $559 million. This includes the associated property
costs as well as the costs of investigations, project management and consenting. To
this, scoped contingencies (between 15% and 25%) have been added to capital
costs and project management costs. This gave a total of $642 million.
Looking at the change of the net present value (NPV) of investing in either 2010,
2011 or 2012, the following benefits NPV of delaying the investments are found:
• One year deferral:
$29.9 million
• Two years deferral: $58.0 million
To this is added the change in NPV of the operations and maintenance costs, which
is $2.0 million for one year and $3.8 million for two years. Hence, the value
presented in the table for a one year deferral is $31.9 million and the value of two
years of deferral is $61.8 million.
Deferring the project more than two years adds around $19 million per year. This is
lower than the value of each of the two first years, but is due to the fact than certain
components are due in 2012 latest.
Deferral of the full investment stream When analysing the generation alternatives, it has been assumed that these options
delay all projected investments from the initial and on to 2042 (i.e. the full
development plans presented in Appendix C). This might not be the case, either
because parts of the investments may have been committed before an investor
commits itself to building a generator (or potentially a contract can be signed with a
supplier of a DSM initiative) – or because some of the components in the
development plans will be needed anyway. However, to bias the analysis towards
generation, this has been the assumption.
The deferral benefits include both investments and operations and maintenance
costs. The table below shows the deferral value of delaying the transmission
reference case (building 220 kV lines) a different number of years.
October 2006
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NORTH ISLAND GRID UPGRADE PROJECT–AMENDED PROPOSAL
APPLICATION FOR APPROVAL - 20 OCTOBER 2006
220 kV reference case
Year of commissioning
$million 2006
2011 2013
NPV of capital costs and O&M costs
770
710
Benefits – 1 year delay
50
46
Benefits – 2 years delay
97
90
Benefits – 3 years delay
141
130
Benefits – 4 years delay
183
168
Benefits – 5 years delay
221
204
Benefits – 6 years delay
257
237
Table E-3. Deferral value of delaying the transmission reference case
A NPV of the capital costs and operation and maintenance costs (O&M) are based
on the GIT model runs presented in Attachment E (Economic Analysis of
Alternatives report). For the reference case, this states a mean NPV of the capital
costs if the first part is commissioned in 2013 of $687 million while mean O&M costs
is $24 million giving $710 million in total. A sensitivity analysis of this run was made
when the first part of the investment, in general the parts due up to 2013, was moved
advanced two years to a 2011 commissioning date. This gave $770 million in total
based on $743 million in mean capital costs and $27 million in O&M costs.
It can be seen that the deferral benefits are quite a lot higher than in the previous
example, but here the full investment stream is deferred while it in the earlier case
only the building of the first line was deferred.
October 2006
© Transpower2006
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