Wairakei Ring Investment Proposal Attachment A - GIT Results - December 2008 - Project Reference: CTNI_TRAN-DEV-01
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Wairakei Ring Investment Proposal
Project Reference: CTNI_TRAN-DEV-01
Attachment A – GIT Results
December 2008Investment Propoal, Atachment A – GIT Results
Document Revision Control
Document Description Date
Number/Version
001/Rev A Wairakei Ring Investment Proposal – Attachment A, GIT 11-2008
Results
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rights reservedInvestment Propoal, Atachment A – GIT Results TABLE OF CONTENTS 1 Introduction................................................................................................................. 4 1.1 Purpose .......................................................................................................................................4 1.2 Glossary/terminology ...................................................................................................................4 1.3 Document structure .....................................................................................................................4 1.4 Compliance with the Grid Investment Test..................................................................................5 2 Moving from refined options to Short-list ................................................................ 5 2.1 Conductor selection for the reconductoring options ....................................................................9 3 Outcomes from the Scenarios................................................................................... 9 3.1 Basis of the scenarios..................................................................................................................9 3.2 Impact of regional constraints on the scenario outputs ...............................................................9 3.3 Impact on generation technology mix........................................................................................10 3.4 Operational Costs ......................................................................................................................12 3.5 Conclusion on reasonableness of generation expansion plans ................................................13 4 Expected Net Market Benefit results ...................................................................... 14 4.1 Overall GIT results.....................................................................................................................14 4.2 GIT results by market development scenario ............................................................................15 4.3 GIT Sensitivities.........................................................................................................................16 4.4 Demand growth .........................................................................................................................16 5 Uncertainty in the results......................................................................................... 22 5.1 Results using SDDP operational costs......................................................................................23 6 Timing of upgrades .................................................................................................. 24 6.1 Longevity of short-list options ....................................................................................................27 7 Conclusion of the Grid Investment Test analysis ................................................. 29 7.1 Conclusions on timing................................................................................................................29 Appendix A Glossary.................................................................................................. 30 Part III 2008 Grid Upgrade Plan: Wairakei Ring Investment Proposal © Transpower New Zealand Limited 2008. All 3 rights reserved
Investment Propoal, Atachment A – GIT Results
1 Introduction
1.1 Purpose
The purpose of this document is to present and explain the results from Transpower’s
application of the grid investment test (GIT), undertaken as a part of the Wairakei Ring
Investment Proposal (the Proposal).
Note that unless otherwise specified all currency numbers presented in this report are pre-
tax and discounted to $2008 at 7%.
1.2 Glossary/terminology
A glossary of terms and acronyms used in this GIT Results paper is included in Appendix A.
All references to rules in this document refer to those in Section III of Part F of the Electricity
Governance Rules 2003 unless otherwise specified.
1.3 Document structure
This document forms part of the Proposal. The documentation is structured according to the
following diagram:
Investment Proposal
Attachment A –
GIT Results
Attachment B –
Assumptions and Approach
Attachment C –
Power System Analysis
Attachment D –
Costing Report
Attachment E –
Final Long-list and Criteria
Attachment F –
Models and Data (in separate files)
Attachment G –
Submissions
This document is set out in four sections:
• The process moving from the combination options to the short-list;
• Outcomes from the scenarios;
• The results; and
• The sensitivities
The approach and assumptions are set out in detail within Attachment B, and engineering
analysis that lead to the options is described in Attachment C.
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1.4 Compliance with the Grid Investment Test
Under Rule 14.4, the Electricity Commission may approve proposed investments where
Transpower has applied the GIT reasonably.
As set out in Section 7.1 of the Proposal, investment in the Wairakei Ring is considered an
economic investment. Therefore, to satisfy the GIT the Proposal must:
• maximise the expected net market benefit compared with a number of alternative
projects, in a robust manner having regard to sensitivity analysis; and
• result in an expected net market benefit greater than zero, in a robust manner
having regard to sensitivity analysis.
Transpower considers that the results set out in this document demonstrate that Transpower
has applied the GIT reasonably and that Option 4 (the new double circuit B line) satisfies the
GIT criteria.
2 Moving from refined options to Short-list
Attachment C, the power system analysis report, sets out the process by which the detailed
short listed options were developed. This consisted of three stages:
1. The selection of eight upgrades (4 for each circuit);
2. Consideration of reasonable combinations of these upgrades;
3. Using the combinations, a staged short-list of options was developed.
This section describes the process that lead from a list of reasonable combinations (step 2)
to the staged short-list options. This was carried out utilising an initial cost benefit analysis of
the upgrade combinations.
The set of combination upgrades are repeated in Table 2-1 below.
Table 2-1 Combination upgrades
Combination A line B line Incremental
Description Description improvement in
injection capacity*
1 Reconductor Leave as is 160 MW
2 Reconductor Reconductor 660 MW
3 Leave as is Replace with a new double 820 MW
circuit line
4 Reconductor Replace with a new double 1400 MW
circuit line
5 Leave as is. Replace with a new double 970 MW
Build a new single circuit line circuit line
from ATI to WRK
6 Reconductor ATI-WKM, leave Replace with a new double 1650 MW
remainder as is. circuit line
Build a new single circuit line
from ATI to WRK (direct)
7 Replace with a new double Replace with a new double 2080 MW
circuit line circuit line
8 Leave ATI-WKM as is. Replace with a new double 900 MW
Replace remainder with new circuit line
double circuit line
9 Leave as is Reconductor - 5 MW
10 Replace with a new double Leave as is 910 MW
circuit line
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Combination A line B line Incremental
Description Description improvement in
injection capacity*
11 Leave as is Leave as is. 540 MW
Build a new single circuit line
form WRK to WKM (via
PPT)
12 Leave as is Leave as is 640 MW
Build a new single circuit line
Each of these combinations was assessed against the 5 market development scenarios, the
results of which are summarised in Table 2-2 below. The timing for all stage 1 investments
was 2014. The timing was an initial estimation based on when constraints were first
observed in the Base Case runs.
Table 2-2: Results from analysing the combination upgrades
Transmission
Benefit Net Market Benefit
Combination Capital Cost
($M) ($M)
($M)
1
160 49 111
(Recon A)
2
502 80 422
(Recon A/ Recon B)
3
512 72 441
(New DBL B)
4
513 102 411
(Recon A / New DBL B)
5
513 102 411
(Add SGL A (ATI) / New DBL B)
6
(Add SGL A (ATI)+ recon / New 513 122 391
DBL B)
7
513 159 354
(New DBL A/ New DBL B)
8
513 118 395
(New DBL A (ATI) / New DBL B)
9
-2 51 -54
(Recon B)
10
513 106 407
(New DBL A)
11
495 60 434
(New SGL B)
12
484 80 404
(New SGL A)
These results where used to derive an initial short-list. Specifically, the results showed that:
• Reconductoring the B line (combination 9) as a first stage had a negative impact on
the benefits. This also confirmed the power system analysis which showed the
capacity increase of the upgrade as being -5MW. Therefore it was not considered
any further as a first stage investment.
• The options that had a combination of new circuits on both sides of the Wairakei
Ring showed benefits that were equivalent to the unconstrained network over the
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entire period. Therefore, this demonstrated that there would be significant benefit
from staging new build options (due to the benefit of delaying capital expenditure)
and that the larger capacity options were going to provide unnecessary over
capacity. Therefore combinations 6 and 7 were not considered any further.
• Some options clearly provided less benefit for greater or similar costs as other
options. Based on this, combinations 5 and 8 were not considered further.
It was clear from this that the short-list of options needed to be staged. The analysis showed
that the logical first stage of each short-list option was likely to be either:
• Reconductor the A line (combination 1); or
• Build a new double circuit B line (combination 3); or
• Build a new single circuit B line (combination 11).
As the net benefit of combination 10 was low, it did not appear that a new build on the A line
was going to be economic. However, there was a higher degree of uncertainty in these initial
results. Accordingly, both the double and single circuit build options on the A line builds
were also included as potential first stage investment options.
The second stage investments were then considered. The analysis results showed that, in
particular, the reconductoring of the A line would need to be closely followed by a second
stage investment. The options for the second stage investment were:
• reconductoring the B line (combination 2),
• build a new double circuit B line (combination 4); or
• a new single circuit B line (this was added later for completeness).
Second stage investments for the new build options were also considered and the timing
tested. For example the double circuit B line was tested with a second stage reconductoring
of the A line. However, it was found that for all new build options a second stage, while
possibly necessary at some time in the future, was uneconomic over the study period given
the current set of inputs. Therefore, second stage investments have not been included as
modelled projects for the new build options. Table 2-3 below summarises the outcomes of
the initial analysis.
Table 2-3 Outcomes of initial analysis
Transmission Net Market
Benefit* Initial
Combination Capital Cost Benefit
($M) Assessment
($M) ($M)
1
160 49 111 Stage 1
(Recon A)
2 Indicative of a
502 80 422
(Recon A/ Recon B) Stage 2 state 1
3
512 72 441 Stage 1
(New DBL B)
4 Indicative of a
513 102 411
(Recon A / New DBL B) Stage 2 state
1
That is, the combination represents that state of the Ring once a second stage investment has been made.
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Transmission Net Market
Benefit* Initial
Combination Capital Cost Benefit
($M) Assessment
($M) ($M)
5
(Add SGL A (ATI) / New DBL 513 102 411 Filtered out
B)
6
(Add SGL A (ATI)+ recon / 513 122 391 Filtered out
New DBL B)
7
513 159 354 Filtered out
(New DBL A/ New DBL B)
8
(New DBL A (ATI) / New DBL 513 118 395 Filtered out
B)
9
-2 51 -54 Filtered out
(Recon B)
10
513 106 407 Stage 1
(New DBL A)
11
495 60 434 Stage 1
(New SGL B)
12
484 80 404 Stage 1
(New SGL A)
* This was an initial analysis only and as such the results differ from those in the final model
runs.
As a result of this process the short-list was developed. Table 2-4 sets out the final short list
used in the analysis.
Table 2-4 Final Short-list options
Short List
Stage 1 Upgrade Stage 2 Upgrade
Option
Base Case Do nothing none
Option 1 Reconductor – A Line Reconductor – B Line
Option 2 Reconductor – A Line New Single Circuit – B Line
Option 3 Reconductor – A Line New Double Circuit – B Line
Option 4 New Double Circuit – B Line none
Option 5 New Single Circuit – B Line none
Option 6 New Double Circuit – A Line none
Option 7 New Single Circuit – A Line None
Notes:
New double circuits include removal of the relevant existing line.
New single circuit options are additional to the existing lines.
The actual alignment of any new build option is subject to more detailed investigation, the assumed
alignments are notional and are used for the purpose of costing only.
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These options have been assessed against the scenarios used in the analysis.
2.1 Conductor selection for the reconductoring options
The conductors used for the reconductoring options are:
• High temperature (ACSS) Pheasant for the A line. Pheasant is cheaper that the
alternative duplex Goat. Pheasant also has a higher summer rating than duplex
Goat. While the winter rating for Pheasant is lower than for duplex Goat, the
analysis showed that the summer transmission ratings bind first and therefore as
Pheasant was selected as the preferred conductor for the A line reconductoring.
• Duplex Zebra for the B line. Duplex Zebra was both cheaper and provided higher
capacity than the alternative Falcon. Therefore it was selected as the preferred
conductor for the analysis.
Attachment D has a description of the transmission costing process.
3 Outcomes from the Scenarios
The purpose of this section is to demonstrate that the scenarios are reasonable and to
illustrate the impact of the transmission options studied. The full details of the inputs, models
and scenario outputs are available in Attachment F.
3.1 Basis of the scenarios
Transpower is required under the rules to use the market development scenarios specified
in the Commission’s SoO, unless the Commission determines that alternative scenarios are
more appropriate. As set out in the GUP and Attachment B, Transpower has made a
number of changes to the input data for these scenarios. A number of required changes
have also been made to the GEM model so as to enable modelling of regional transmission
augmentations. Transpower considers that these changes are reasonable to make in the
context of the Wairakei Ring, and seeks a determination by the Commission that the
alternative scenarios are more appropriate than the scenarios specified in the SoO.
Three examples from the analysis have been used to illustrate the impact of the changes:
1. the impact of regional constraints on the scenario outputs;
2. the impact on the generation technology mix; and
3. the use of SDDP to verify the operational costs. This is an alternative method for
testing the fuel costs from the GEM output.
Each of these is discussed in the following sections.
3.2 Impact of regional constraints on the scenario outputs
The most significant change from the SoO scenarios published by the Commission is the
implementation of a constrained regional transmission network. The impact of the
constrained network can be seen by considering the relative regional generation build
between the base case (with constraints that reflect current transmission capacities and a
fully unconstrained network) and a completely unconstrained network. This is shown in the
following graph for MDS 1:
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Figure 3-1: Relative Generation Build for MDS 1
Installed MW - Base verses Unconstrained for mds 1, by region
12000
10000
8000 Base SI
Uncon SI
Installed MW
Base UNI
Uncon UNI
6000
Base LNI
Uncon LNI
Base WRK
4000 Uncon WRK
2000
0
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
Year
The main features from this are:
• The investment in the Wairakei area is significantly lower in the base case than in
the unconstrained case (shown by the lower arrow).
• This is mirrored by an increase in the required thermal generation in the upper North
Island for the base case, compared with the unconstrained case.
• Investment in the South Island and the lower North Island is only slightly impacted
by the Wairakei Ring.
The pattern of generation investment shown in the above graph is consistent with a
constrained Wairakei Ring, and therefore Transpower considers that these results
demonstrate the scenarios used in the analysis are reasonable.
3.3 Impact on generation technology mix
A feature of the SoO scenarios is the change in generation mix between scenarios (ranging
from more renewables in scenario 1 through to the more thermally based scenario 5). As the
scenarios used for this GIT analysis are largely based on the SoO scenarios, this same
theme should be evident in the scenarios developed for this GIT analysis. The only
significant deviation results from the use of a constrained network and the updates
Transpower has made in the early years of each scenario. The graphs below demonstrate
that the general trends for generation technology mix developed within each SoO scenario
have been carried through the Wairakei Ring analysis.
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Figure 3-2: Base case installed MW by MDS
The graphs clearly show the greater amounts of wind and smaller amounts of gas and coal
in MDS 1 compared with MDS 5. This is further illustrated in the following graphs showing
the GWhs generation by fuel type.
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Figure 3-3: Base case GWh Generation by MDS
Transpower considers that the trends illustrated by these graphs indicate that the use of the
proposed alternative scenarios is reasonable for this analysis.
3.4 Operational Costs
In order to verify the operational costs derived by the GEM model, which does not consider a
full range of hydrology, Transpower conducted analysis using SDDP. To do this, the
generation build sequence for each scenario was taken from GEM and simulated over 74
hydro sequences in SDDP. The following graph illustrates the absolute differences between
the average operational costs from SDDP and the operational costs derived from GEM for
the base case (the most constrained) for scenario 1.
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Figure 3-4: Operating Cost Comparison GEM - SDDP
Operating Cost Comparison - GEM Verses SDDP
2,000,000
1,800,000
1,600,000
1,400,000
Operating Cost ($k)
1,200,000
1,000,000
800,000
600,000
400,000 SDDP Operating Cost
GEM Operating Cost
200,000
-
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
Year
Note: the numbers shown in the graph have discounting and tax effects removed in order to illustrate the absolute
differences.
The graph illustrates that the operational costs from GEM, which are based on average
hydrology only (input parameter), aligns relatively closely with the average operational costs
output from SDDP for the 74 hydro sequences. While GEM overstates the operational costs
this is not considered significant as:
• the same pattern of operational costs can be observed between the two models with
the correlation between the two series being approximately 0.97; and
• testing has shown the differences between operational costs between transmission
options is relatively consistent.
Testing of the input data showed that the primary driver for the differences was the level of
minimum utilisation assumed for existing generation plant by the Commission in the SoO
scenarios. The results are relatively sensitive to these factors and some relaxation of these
constraints yielded results that almost exactly aligned the results from SDDP and GEM.
However, for the purposes of this analysis, Transpower has adopted the settings used by
the Commission in the SoO scenarios.
However, what the differences do illustrate is that there is significant uncertainty in both the
assumptions and the results of the analysis. This uncertainty is driven, not only by the
inherent uncertainty in the inputs, but also by the large difference in magnitudes between the
option costs and the benefits being modelled. This is discussed further in Section 5 of this
report along with the results using of the analysis from SDDP.
3.5 Conclusion on reasonableness of generation expansion plans
Given that:
• the general trends shown by the scenario analysis are as expected;
• the impact of a constrained network on the build patterns is also expected; and
• the changes Transpower has made to the scenario input data are only minor,
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Transpower concludes that GEM is producing reasonable generation expansion plans and
that these generation expansion plans are suitable for assessing the economics of
upgrading the Wairakei Ring. Full details of all the input assumptions and outputs are
available in Attachment F.
4 Expected Net Market Benefit results
This section sets out the results for the transmission options studied. It covers the:
• overall GIT results;
• sensitivities; and
• uncertainty in the results.
The options have been analysed over a range of three demand growth assumptions, five
market development scenarios and a range of other sensitivities. In terms of presentation in
the remainder of this document, please note that:
• net market benefits highlighted in green indicate a result that satisfies the GIT; and
• net market benefits highlighted in orange indicate the highest net market benefit of
the options, but that the result does not satisfy the GIT.
The results reported in this document are the expected net market benefits only. Unless
otherwise stated all results are those taken from the GEM modelling only. Results using
SDDP to calculate operational costs are set out in section 5.1 below.
4.1 Overall GIT results
The weight averaged expected net market benefit for each short list option is:
Table 4-1: Overall results of application of the Grid Investment Test
Item Generation Generation Transmission Terminal Expected Net
fixed variable costs (C) benefit (D) Market Benefit
benefits (A) benefits
(B) (A+B-C+D)
Base Case 0 0 0 0 0
Option 1 -146 593 83 105 468
Option 2 -136 577 96 102 448
Option 3 -157 607 93 110 467
Option 4 -162 616 71 110 493
Option 5 -134 574 63 100 477
Option 6 -160 610 102 110 458
Option 7 -129 563 82 98 451
Notes:
Costs and benefits are all pre-tax, discounted at 7%, in $m, and in $2008.
These results show that Option 4, a new double circuit B line has the highest expected net
market benefit of the short-list options, being some $16 million in 2008 present value terms
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higher than the next highest alternative project, Option 5 (a new additional single circuit B
line).
The expected net market benefit of Option 4 is $493 million (forecast to arise over 20 years
from commissioning of the new double circuit B line) and, being greater than zero,
Transpower concludes that Option 4, therefore, meets the requirements of clauses 4.2.1 and
4.2.2 of the GIT.
Transpower has considered the sensitivity of this result to changes in key variables and
parameters to assess the robustness of this result (in accordance with clause 4.2.3 of the
GIT).
4.2 GIT results by market development scenario
Table 4-2 shows the GIT results by market development scenario, weight averaged over the
demand growth scenarios.
Table 4-2: Results of application of the Grid Investment Test by generation scenario
Net Market Benefit MDS1 MDS2 MDS3 MDS4 MDS5
Option 1 862 456 605 266 152
Option 2 818 444 587 252 139
Option 3 891 438 603 261 142
Option 4 914 469 634 283 164
Option 5 834 477 619 281 172
Option 6 879 431 595 252 133
Option 7 809 451 585 255 153
Notes:
Costs and benefits are all pre-tax, discounted at 7% and in $2008.
The final GIT result is derived by applying equal weightings to the scenarios as defined in
the 2008 SoO and detailed in Attachment B.
The results show a decreasing value of an upgrade for the scenarios in which more thermal
generation is built (although still positive), and the differences between options also
decreases. This is shown in Table 4-3 below which illustrates the difference between each
option and the option with the highest benefit in each scenario.
Table 4-3 Relative difference in net benefits between options
Net Market Benefit MDS1 MDS2 MDS3 MDS4 MDS5
Option 1 -52 -21 -29 -17 -20
Option 2 -96 -34 -47 -31 -33
Option 3 -23 -40 -31 -22 -30
Option 4 0 -8 0 0 -8
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Net Market Benefit MDS1 MDS2 MDS3 MDS4 MDS5
Option 5 -79 0 -15 -2 0
Option 6 -35 -47 -40 -31 -39
Option 7 -105 -26 -49 -28 -19
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% and in $2008.
These results indicate that:
• scenario 1 drives the largest portion of the overall benefits;
• Option 4 has the highest expected net market benefit in the renewables scenario
(mds1) and scenarios 3 and 4;
• Option 5 has the highest net benefit in scenario 2 and 5. However, of note, the
difference between Option 4 and 5 is small in scenarios 2 and 5;
• Option 4 and Option 5, both new build options, come out ahead of the other options;
and
• the larger capacity options, Options 3, 4 and 6, have a definite advantage under the
renewables scenario.
4.3 GIT Sensitivities
Transpower has carried out the following sensitivities to consider the robustness of the GIT
result as part of its proposed GIT application:
• demand, high and low as in the 2008 SoO;
• discount rates, 4% and 10%;
• transmission capital costs, low - 80% and high - 120%;
• exchange rates, 10 year rolling average;
• carbon costs, low - 80%, high – 120%; and
• property costs, 200%.
The results from each are described in the following sections.
4.4 Demand growth
To test this sensitivity, both high and low demand is used to calculate the benefits in GEM.
Table 4-4 shows the GIT results by demand growth scenario, weight averaged over the
market development scenarios:
Table 4-4: Results of application of the Grid Investment Test by demand scenario
Net Market Benefit Low Demand Medium High Demand
Demand
Option 1 341 468 554
Option 2 323 448 527
Option 3 342 467 546
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Net Market Benefit Low Demand Medium High Demand
Demand
Option 4 364 493 588
Option 5 351 477 559
Option 6 333 458 536
Option 7 330 451 509
Notes:
Costs and benefits are all pre-tax, discounted at 7% and in $2008.
These results indicate that each short list option has a greater expected net market benefit
as demand growth increases. This is reasonable, because as demand growth increases, the
requirement for new generation north of the Wairakei ring would increase and the potential
savings from increased capacity around the Wairakei ring would also increase.
Option 4 is the most economic for all three demand growth options. Additionally, as demand
grows, the larger capacity of Option 4 creates greater benefits relative to the next best
alternative, Option 5, and the reconductoring option, Option 1.
4.4.1 Discount Rate – 4%, 7% and 10%
To test this sensitivity, the discount rates used to calculate the present values is 4%, 7% (the
base GIT results) and 10%.
Table 4-5: Results of application of the Grid Investment Test - 4% discount rate sensitivity
Net Market Benefit 4% 7% (base 10%
results)
Option 1 926 468 246
Option 2 893 448 232
Option 3 933 467 242
Option 4 966 493 261
Option 5 922 477 257
Option 6 922 458 235
Option 7 885 451 238
Notes:
Costs and benefits are all pre-tax, in $m and in $2008.
The significant conclusion to note is the double circuit B line (Option 4) comes out ahead for
all the cases.
4.4.2 Capital Costs
To test this sensitivity, the capital cost of the transmission equipment is varied between 80%
and 120% of the expected cost used by Transpower in the GIT analysis.
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Table 4-6: Results of application of the Grid Investment Test – Transmission capital costs
sensitivity
Expected Net Market Benefit Low (80%) Base (100%) High (120%)
Option 1 483 468 454
Option 2 464 448 432
Option 3 484 467 450
Option 4 505 493 481
Option 5 485 477 468
Option 6 476 458 440
Option 7 463 451 438
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% and in $2008.
Significant conclusions to note are:
• Option 4 consistently comes out ahead of the other options.
• The separation in expected net market benefits between Option 4 and the option with
the next highest benefit increases as the capital cost decreases.
4.4.3 Exchange rate variations
To test this sensitivity, the exchange rates used to calculate the capital cost of the
transmission equipment are varied from being an average calculated around +/- 20 business
days of 1 September 2008 to an average calculated around the last ten years exchange
rates.
Table 4-7: Results of application of the Grid Investment Test - exchange rate sensitivity
Expected Net Market Benefit Base 10 yr average
(+/- 20 business days
around 1 September)
Option 1 468 467
Option 2 448 447
Option 3 467 464
Option 4 493 491
Option 5 477 476
Option 6 458 456
Option 7 451 450
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% and in $2008.
Significant conclusions to note are:
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• The expected net market benefit is not particularly sensitive to the exchange rate
basis used.
• The ranking of the short-list options does not change.
• Both results show Option 4 has the highest expected net market benefit.
4.4.4 Property Costs
An additional sensitivity has been carried out on the property cost component of the options.
This is done so as to verify the impact that property has on the ranking between the
reconductoring option and the new build options. To test this sensitivity, the property cost for
all the options has been doubled.
Table 4-8: Results of application of the Grid Investment Test - Property cost sensitivity
Expected Net Market Benefit Base 200% property
cost
Option 1 468 463
Option 2 448 440
Option 3 467 459
Option 4 493 487
Option 5 477 471
Option 6 458 450
Option 7 451 442
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% and in $2008.
Significant conclusions to note are:
• While the total expected net market benefit is sensitive to property costs, the ranking
of the options does not change.
• Both results show Option 4 has the highest expected net market benefit.
4.4.5 Carbon Costs
A sensitivity has been run using a +/- 20% variation on carbon costs. The results are shown
below in Table 4-9.
Table 4-9 Carbon cost sensitivity
Expected Net Market Low (80%) Base (100%) High (120%)
Benefit
Option 1 455 468 478
Option 2 435 448 458
Option 3 452 467 476
Option 4 479 493 502
Option 5 464 477 486
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Expected Net Market Low (80%) Base (100%) High (120%)
Benefit
Option 6 443 458 467
Option 7 439 451 457
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% and in $2008.
The significant conclusions to note are:
• The higher carbon costs create a greater benefit for upgrading the transmission
around the Wairakei Ring. This is reasonable as the cost of thermal generation
becomes more expensive. Therefore the benefit gained from renewables will be
greater i.e. they become relatively cheaper. Additionally, as a consequence of
renewable generation being more likely to be located either within or south of the
Wairakei Ring, the greater the benefit gained from an upgrade.
• All results show Option 4 has the highest expected net market benefit.
4.4.6 Summary table of sensitivity results
Table 4-10 summarises the overall results and the sensitivities.
Table 4-10: Sensitivity of expected net market benefit of the short-list options
Expected Net Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Market Benefit
Base results 468 448 467 493 477 458 451
Sensitivity:
Discount rate, 4% 926 893 933 966 922 922 885
Discount rate,
10% 246 232 242 261 257 235 238
Capital 80% 483 464 484 505 485 476 463
Capital 120% 454 432 450 481 468 440 438
10 yr avg
exchange rate 467 447 464 491 476 456 450
High demand 554 527 546 588 559 536 509
Low Demand 341 323 342 364 351 333 330
Property Costs
(200%) 463 440 459 487 471 450 442
Low Carbon Cost
(80%) 455 435 452 479 464 443 439
High Carbon Cost
(120%) 478 458 476 502 486 467 457
Notes:
Costs and benefits are all pre-tax, in $m, discounted at 7% (unless otherwise stated) and in $2008.
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This summary shows that the ranking of the short-list options is stable to a range of
sensitivities. All sensitivities show Option 4, the new double circuit B line, having the highest
positive expected net market benefit.
Table 4-11 below shows the differences in expected net market benefit between each option
and the option with the highest expected net market benefit.
Table 4-11 Differences in net benefits
Expected Net Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7
Market Benefit
Base results -24 -45 -26 0 -16 -35 -42
Sensitivity:
Discount rate, 4% -41 -74 -33 0 -44 -44 -81
Discount rate,
-16 -29 -20 0 -4 -27 -23
10%
Capital 80% -22 -41 -21 0 -19 -29 -42
Capital 120% -27 -49 -31 0 -13 -40 -43
10 yr avg
-24 -44 -27 0 -15 -35 -42
exchange rate
High demand -34 -62 -42 0 -29 -52 -79
Low Demand -23 -41 -22 0 -13 -31 -34
Property Costs
-24 -46 -27 0 -16 -37 -44
(200%)
Low Carbon Cost
-23 -44 -26 0 -14 -35 -40
(80%)
High Carbon Cost
-24 -44 -26 0 -16 -35 -45
(120%)
Average
Difference (un -26 -47 -27 0 -18 -36 -47
weighted)
The results show that the differences between Option 5, the new single circuit and Option 4,
the new double circuit are close but consistently favour the new double circuit.
The results for Option 4 are also shown diagrammatically below, in order to demonstrate
what the expected net market benefit is most sensitive to.
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Figure 4-1: Sensitivity ranges of expected net market benefit
5 Uncertainty in the results
The results set out in this document have uncertainty associated with them. The uncertainty
arises from three sources:
1. uncertainty inherent in the input assumptions. The modelling assumes certain
generation costs which may or may not be accurate;
2. uncertainty in the problem formulation. The fact that the analysis is assessing
the differences in generation investment and operation costs over 35 years (with
an NPV of $20+ billion) can lead to a high degree of uncertainty in the results.
To some extent this is mitigated by considering the results over five scenarios.
However, aspects such as competitive response and unexpected and structural
changes (such as a big gas discovery or large step change in demand) could
contribute to the scenarios modelled not being representative of the actual
future;
3. the large difference in magnitude of the benefits of each option and the relatively
small difference between the cost of each transmission option. An indication of
this can be seen in
4. Figure 4-1 above where the value changes due to the scenario swamps the
value change due to a change in capital cost.
Therefore small changes in the assumptions are highly likely to change the results of this
analysis.
However, as noted in the GUP and these attachments, Transpower has taken steps to
mitigate these impacts as much as possible by:
• integrating commercial behaviour into the earlier years of the scenarios by fixing the
build dates for a representative sample of generation investments that are already
committed to by investors;
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• testing the transmission options over a range of sensitivities; and
• verifying the operational costs using SDDP (set out below). This provides verification
using a different method of calculation and accounts for hydrological uncertainty.
Therefore, Transpower considers that, given the level of information currently available, the
application of the GIT to the transmission options is reasonable and that any changes to the
assumptions and modelling parameters is likely to lead to changes in the option benefits that
are common across all the options.
As set out in the GUP, Transpower has also considered a number of un-quantified benefits
of the options and concludes that in the long term Option 4, is the most appropriate first
stage option for the Wairakei Ring.
5.1 Results using SDDP operational costs
The following table sets out the overall GIT results using the operational costs derived using
SDDP. SDDP tends to show higher constraint costs when the more detailed and accurate
dispatch of the system is accounted for. The results are significantly higher as a result.
Table 5-1 Overall GIT results using SDDP
Item Generation Generation Transmission Terminal Expected Net
fixed variable costs (C) benefit (D) Market Benefit
benefits benefits
(From GEM) (B) (A+B-C+D)
(A)
Option 1 -146 843 83 124 738
Option 2 -136 849 96 122 740
Option 3 -157 873 93 138 760
Option 4 -162 886 71 128 780
Option 5 -134 839 63 130 771
Option 6 -160 875 102 135 748
Option 7 -129 762 82 114 665
Notes:
Benefits are all pre-tax, discounted at 7%, in $m, and in $2008.
The results using SDDP show that:
• Option 4 still has the highest net benefit;
• operational benefits are significantly higher when hydrology is specifically accounted
for and more detailed dispatch of the system. This is due to the network being
generally more constrained;
• there is some change in the ranking of the options, with the larger capacity options
benefiting; and
• the greater level of constraint means that a second stage investment is likely to be
economically warranted at some in the future, although this has not been tested.
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6 Timing of upgrades
Sensitivity analysis on the timing of all the options was carried out using GEM. This showed
that the optional economic timing for the options is either 2015 or 2016. The optimal
economic timing depends on the benefit derived from delay in capital expenditure relative to
the increase in constraint costs as a result of incurring that delay.
The optimal economic timing for Option 4 is 2015. This equates to a commissioning date
sometime during 2014, in order for the proposal to be in place for 2015. The timing analysis
is illustrated, using Option 4 as an example, in Figure 6-1 below.
Figure 6-1 GEM Optimal Economic Timing
GEM Optimal Economic Timing, Option 4
Optimal economic timing
8 500
490
7
480
Incremental costs/benefits ($m)
6
470
Total Net Benefit ($m)
5
460
4 450
440
3
430
2
420
1
410
0 400
2014 2015 2016 2017
Incremental Capital Cost Savings Change in Generation Costs Expected Net Market Benefit
The graph shows that the net economic benefit (based on GEM runs) is maximised in 2015
i.e. the date in which the incremental savings from delaying transmission investment is equal
to the cost increase in generation costs.
However, there are several important factors that point to a preference for an earlier
commissioning date:
1. The difference between the net benefit for 2015 and 2014 is relatively small. For
example, for Option 4 it is $3.6 million. Therefore, given the uncertainty and the potential
impact of providing insufficient transmission capacity, Transpower considers it is prudent
to bring forward the date in which the transmission is required.
2. The risk associated with delayed commissioning is asymmetric. The market cost of
constraints increases exponentially compared with the cost (in NPV terms) of bringing
forward an investment by a year or so. There are a number of factors that may result in
the delay to commissioning, including the RMA process and construction delays.
3. The cost of spill and hydro variability has not been factored into the timing analysis
undertaken using GEM. SDDP analysis shows that in wet years, constraint costs tend to
rise between 1 and 2 years earlier than shown in the average results produced by GEM.
The impact of hydro variations on the marginal constraint cost is shown in Figure 6-2
below.
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Figure 6-2: Marginal Constraint Cost, Base case, Scenario 1
Marginal Constraint Cost, Base Case, scenario 1
1,600
1,400
1,200 Optimal economic
timing, 2015
1,000
Average
k$/MW
800 5th Percentile
95th Percentile
600
400 Hydrology Impact
200
0
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
Year
The graph shows that the variation in constraint costs due to hydrology is between 1 and
2 years. In particular wetter hydro sequences will tend to introduce constraints through
the Wairakei Ring from about 2013 onwards. As a result, SDDP tends to suggest an
earlier optimal economic timing than GEM. Table 6-1 shows the difference in present
value of the generation dispatch benefit as modelled by SDDP for Option 4 relative to
2015. The results show an $8m increase in benefits from improved generation dispatch
from moving the timing of the transmission investment forward to 2014, which implies a
2013 commissioning date. It also illustrates the exponential risk of delayed
commissioning with a loss of $34m moving from 2015 to 2016.
Table 6-1 Generation Dispatch Benefit, as modelled by SDDP, Option 4, $m
Year of Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Average
Investment
2014 9 9 21 1 0 8
2015 0 0 0 0 0 0
2016 -47 -41 -38 -44 -1 -34
Notes:
Benefits are all pre-tax, discounted at 7%, in $m, and in $2008.
4. In the base modelling, GEM allows many of the new generation stations to be built in
stages. 2 In reality it is likely that many of these generators will be built in much larger
steps within a much shorter length of time (that is, new generation plant tends to be
more “lumpy”). This is particularly true for some plant types e.g. geothermal. Therefore it
is likely that constraints around the Wairakei ring would bind earlier than suggested by
2
Due to the complexity of the constraint equations being solved within GEM a relaxed mixed integer method is
used to derive the generation expansion paths. As a result, GEM allows many of the new generators to be built
in stages over a number of years to match demand growth.
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Transpower’s GEM analysis, and consequently, would lead to an earlier optimal timing.
The impact of this has been tested using SDDP. The following graph illustrates the
constraint values increase significantly between 2013 and 2014.
Figure 6-3 - Constraint cost for block build
Constraint Marginal Costs for Original Generation Build Plan and Blocked Build Plan MDS1 Option4
900
ATIOHKPPIWK1 Original
ATIOHKPPIWK1 BlockBuild2015
800
700
600
Marginal Cost (k$/MW)
500
400
300
200
100
0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
The constraint values in Figure 6-3 drop to zero following the construction of the new
double circuit in 2015.
5. Contact Energy has indicated that it is likely to be seeking resource consents for the
Tauhara geothermal power station, near Wairakei, in the near future with a view to
commissioning the plant in 2013. While this has not been treated as a fixed build in the
scenarios, as it is not yet in the consenting process, given its potential impact on the
Wairakei Ring, a sensitivity has been conducted on the impact it may have on the timing.
At present Tauhara is progressively built by GEM from 2014. If Tauhara was to be built
earlier in 2013 it would add to the constraints around the Wairakei Ring and bring the
need date for investment forward. Figure 6-4 illustrates this impact. The analysis was
carried out using the “block build” data described in 4 above.
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Figure 6-4 - Impact of Tauhara on constraint values
Constraint Marginal Cost for ATI-OHK, PPI-WKM-1 Constraint
900
Tauhara built in stages from 2014
800 Tauhara built in 2013
700
Constraint Marginal Cost (k$/MW)
600
500
400
300
200
100
0
2008
2009
2010
2011
2012
2013
2014
2015
2016
This shows that Tauhara has as a cumulative impact on the constraint, increasing the
constraint cost in 2013 and therefore bringing the need date for the investment further
forward. This would suggest that 2012 is an appropriate commissioning date. However,
there are potential practical difficulties with construction of a new line within that
timeframe.
6. Earlier investment is also likely to lead to an increase in un-quantified benefits, such as
competition and ancillary service benefits.
7. There was substantial support of an even earlier 2012 commissioning date from
submitters.
For these reasons, Transpower considers that:
• the optimal timing investments based on the GEM economic criteria only significantly
underestimates the costs and risks associated with construction delays; and
• taking into account the GEM optimal economic timing (and its potential shortcomings),
the SDDP results and timing analysis, un-quantified benefits, and construction
timeframe, there is a strong case for bring forward the commissioning date on the
basis that this will result in earlier realisation of market benefits and avoidance of
asymmetric risks, with only a relatively small increase in the overall cost of the
Proposal (in NPV terms).
Therefore Transpower considers that a target commissioning date of early to mid 2013 is
appropriate.
6.1 Longevity of short-list options
While not part of the requirements for the GIT analysis as set out in the rules, Transpower
considers that the frequency that which an area of the grid needs to be addressed is an
important consideration that should be included in the assessment of the benefits of an
option. This is because there is often significant impact on local communities that arise and
the cumulative social and economic costs that cannot be quantified. Repeated visits to the
same sections of the grid is also indicative of continuing fine operating margins which are
likely to result in additional costs (such as a reduction in competition benefits and market
costs incurred through the requirement for ongoing outage windows) that also cannot be
quantified.
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As such, Transpower has attempted to illustrate the differences in the longevity of the
options in Figure 6-5 below.
Figure 6-5 Longevity of Short-list options
This clearly shows that the options with the highest capacity such as option 4, the double
circuit B line and option 6 the double circuit A line requires the least disruption to both
communities and the electricity market.
Note that the timings for the red bars are indicative only as optimisation of the follow on
stages was not explicitly carried out in the analysis. However, they have been approximated
based on constraint cost information derived from the scenarios.
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7 Conclusion of the Grid Investment Test analysis
Transpower concludes that Option 4, a new double circuit 220 kV line along the alignment of
the existing B line, satisfies the GIT because:
• it maximises the expected net market benefit when compared with the alternative
projects;
• it has a positive net market benefit; and
• it is robust having regard to the results of a sensitivity analysis.
It is noted that whilst the expected net market benefit of Option 4 is $493 million, this is
averaged over five market development scenarios and uses a 7% discount rate.
These results are robust to the wide range of sensitivity analysis carried out by Transpower.
7.1 Conclusions on timing
After consideration of both the numerical results and the un-quantified benefits accruing from
the Proposal, Transpower considers that the appropriate planned commissioning date for
the preferred option, a new double circuit B line, is early to mid 2013.
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Appendix A Glossary
Term Description
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).
Base Case The “do nothing” option, a counterfactual for other options to be
considered against.
CCGT Combined Cycle Gas Turbine
Consultation Paper Document published by Transpower on 28 October 2008.
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 Rules. In the context of this document, it
generally refers to Part F Transport, Section III Grid Upgrade and
Investments, 28 June 2007.
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.
GEM Generation Expansion Model, a model for generation expansion
modelling originally developed by the Electricity Commission.
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.
Grid Planning Principles for these are contained in Rule 10 Electricity
Assumptions Governance Rules. The Rule provides that assumptions should
cover a reasonable range pf credible forecasts and scenarios;
should have a length of outlook commensurate with consideration
of future investment in long-life transmission assets; and should be
as accurate as possible.
HVDC High Voltage Direct Current
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LNG Liquified Natural Gas
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.
New Zealand Energy The New Zealand Energy Strategy to 2050 sets out the
Strategy government's vision for a reliable and resilient system to deliver a
sustainable, low emissions energy services.
PLEXOS A proprietary power market model suitable for short, medium and
longer term studies including generation expansion planning. It
can furthermore model market behaviour to assess competition
benefits.
Rules The Electricity Governance Rules 2003.
SDDP Stochastic Dual Dynamic Programming, a hydro-thermal dispatch
model with representation of the transmission network used for
short, medium and long term operation studies.
SRMC Short Run Marginal Cost
SOO Statement of Opportunities, published by the Electricity
Commission
Transpower Transpower New Zealand Limited, owner and operator of New
Zealand’s high-voltage electricity network (the national grid).
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