Wairakei Ring Investment Proposal. Project Reference: CTNI_TRAN-DEV-01. Attachment A GIT Results

Wairakei Ring Investment Proposal Project Reference: CTNI_TRAN-DEV-01 Attachment A GIT Results December 2008

Document Revision Control Document Number/Version 001/Rev A Description Wairakei Ring Investment Proposal Attachment A, GIT Results Date 11-2008 2

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 3

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 pretax 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. 4

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 Description B line Description 1 Reconductor Leave as is 160 MW 2 Reconductor Reconductor 660 MW Incremental improvement in injection capacity* 3 Leave as is Replace with a new double circuit line 4 Reconductor Replace with a new double circuit line 820 MW 1400 MW 5 Leave as is. Build a new single circuit line from ATI to WRK 6 Reconductor ATI-WKM, leave remainder as is. Build a new single circuit line from ATI to WRK (direct) 7 Replace with a new double circuit line 8 Leave ATI-WKM as is. Replace remainder with new double circuit line Replace with a new double circuit line Replace with a new double circuit line Replace with a new double circuit line Replace with a new double circuit line 970 MW 1650 MW 2080 MW 900 MW 9 Leave as is Reconductor - 5 MW 10 Replace with a new double circuit line Leave as is 910 MW 5

Combination A line Description B line Description Incremental improvement in injection capacity* 11 Leave as is Leave as is. Build a new single circuit line form WRK to WKM (via PPT) 540 MW 12 Leave as is Build a new single circuit line Leave as is 640 MW 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 Combination Benefit ($M) Transmission Capital Cost ($M) Net Market Benefit ($M) 1 (Recon A) 2 (Recon A/ Recon B) 3 (New DBL B) 4 (Recon A / New DBL B) 5 (Add SGL A (ATI) / New DBL B) 6 (Add SGL A (ATI)+ recon / New DBL B) 7 (New DBL A/ New DBL B) 8 (New DBL A (ATI) / New DBL B) 9 (Recon B) 10 (New DBL A) 11 (New SGL B) 12 (New SGL A) 160 49 111 502 80 422 512 72 441 513 102 411 513 102 411 513 122 391 513 159 354 513 118 395-2 51-54 513 106 407 495 60 434 484 80 404 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 6

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 Combination Benefit* ($M) Transmission Capital Cost ($M) Net Market Benefit ($M) Initial Assessment 1 (Recon A) 160 49 111 Stage 1 2 (Recon A/ Recon B) 502 80 422 Indicative of a Stage 2 state 1 3 (New DBL B) 512 72 441 Stage 1 4 (Recon A / New DBL B) 513 102 411 Indicative of a Stage 2 state 1 That is, the combination represents that state of the Ring once a second stage investment has been made. 7

Combination Benefit* ($M) Transmission Capital Cost ($M) Net Market Benefit ($M) Initial Assessment 5 (Add SGL A (ATI) / New DBL B) 6 (Add SGL A (ATI)+ recon / New DBL B) 7 (New DBL A/ New DBL B) 8 (New DBL A (ATI) / New DBL B) 9 (Recon B) 10 (New DBL A) 11 (New SGL B) 12 (New SGL A) 513 102 411 Filtered out 513 122 391 Filtered out 513 159 354 Filtered out 513 118 395 Filtered out -2 51-54 Filtered out 513 106 407 Stage 1 495 60 434 Stage 1 484 80 404 Stage 1 * 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 Option Stage 1 Upgrade Stage 2 Upgrade 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. 8

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: 9

Figure 3-1: Relative Generation Build for MDS 1 Installed MW - Base verses Unconstrained for mds 1, by region 12000 10000 Installed MW 8000 6000 4000 Base SI Uncon SI Base UNI Uncon UNI Base LNI Uncon LNI Base WRK 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. 10

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. 11

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. 12

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, 13

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 fixed benefits (A) Generation variable benefits (B) Transmission costs (C) Terminal benefit (D) Expected Net Market Benefit (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 14

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 15

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 Demand High Demand Option 1 341 468 554 Option 2 323 448 527 Option 3 342 467 546 16

Net Market Benefit Low Demand Medium Demand High 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 results) 10% 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. 17

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 (+/- 20 business days around 1 September) 10 yr average 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: 18

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 Benefit Low (80%) Base (100%) High (120%) 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 19

Expected Net Market Benefit Low (80%) Base (100%) High (120%) 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 Market Benefit Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7 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. 20

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 Market Benefit Option 1 Option 2 Option 3 Option 4 Option 5 Option 6 Option 7 Base results -24-45 -26 0-16 -35-42 Sensitivity: Discount rate, 4% -41-74 -33 0-44 -44-81 Discount rate, 10% -16-29 -20 0-4 -27-23 Capital 80% -22-41 -21 0-19 -29-42 Capital 120% -27-49 -31 0-13 -40-43 10 yr avg exchange rate -24-44 -27 0-15 -35-42 High demand -34-62 -42 0-29 -52-79 Low Demand -23-41 -22 0-13 -31-34 Property Costs (200%) Low Carbon Cost (80%) High Carbon Cost (120%) Average Difference (un weighted) -24-46 -27 0-16 -37-44 -23-44 -26 0-14 -35-40 -24-44 -26 0-16 -35-45 -26-47 -27 0-18 -36-47 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. 21

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; 22

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 fixed benefits (From GEM) (A) Generation variable benefits (B) Transmission costs (C) Terminal benefit (D) Expected Net Market Benefit (A+B-C+D) 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. 23

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 8 7 GEM Optimal Economic Timing, Option 4 Optimal economic timing 500 490 Incremental costs/benefits ($m) 6 5 4 3 2 1 480 470 460 450 440 430 420 410 Total Net Benefit ($m) 0 2014 2015 2016 2017 Incremental Capital Cost Savings Change in Generation Costs Expected Net Market Benefit 400 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. 24

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 k$/mw 800 600 Average 5th Percentile 95th Percentile 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 Investment Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Average 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. 25

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 900 800 ATIOHKPPIWK1 Original ATIOHKPPIWK1 BlockBuild2015 700 Marginal Cost (k$/mw) 600 500 400 300 200 100 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. 26

Figure 6-4 - Impact of Tauhara on constraint values 900 Constraint Marginal Cost for ATI-OHK, PPI-WKM-1 Constraint 800 Tauhara built in stages from 2014 Tauhara built in 2013 700 600 500 400 300 200 100 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 Constraint Marginal Cost (k$/mw) 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. 27

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. 28

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. 29

Appendix A Glossary Term Alternative Project Base Case Description 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). 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 GEM 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. Generation Expansion Model, a model for generation expansion modelling originally developed by the Electricity Commission. GIT Grid Planning Assumptions HVDC 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. Principles for these are contained in Rule 10 Electricity 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. High Voltage Direct Current rights reserved 30

LNG modelled projects New Zealand Energy Strategy Liquified Natural Gas 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. The New Zealand Energy Strategy to 2050 sets out the 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 SRMC Stochastic Dual Dynamic Programming, a hydro-thermal dispatch model with representation of the transmission network used for short, medium and long term operation studies. 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). rights reserved 31