KAWERAU GENERATION EXPORT ENHANCEMENT INVESTMENT PROPOSAL December GRID UPGRADE PLAN 2009 Instalment 9 Part XII

Transcription

1 KAWERAU GENERATION EXPORT ENHANCEMENT INVESTMENT PROPOSAL December 2011 GRID UPGRADE PLAN 2009 Instalment 9 Part XII

2 Executive Summary A new geothermal power station (installed capacity of 25 MW) is being built at Kawerau with commissioning expected in December The amount of electricity that can be injected into the 110 kv bus at Kawerau is already limited from time to time. With more generation at Kawerau, these constraints on generation are likely to occur more often. We estimate that by removing these constraints and allowing all the existing geothermal and hydro generation at Kawerau (including the new power station) to be exported to the wider grid, the total cost of producing electricity could reduce by between $20-27 million. By providing some spare interconnection capacity into the 220 kv network we should enable the future development of low cost geothermal generation in the Eastern Bay of Plenty. The information we have received through our consultation has highlighted the potential for significant geothermal development in the area. Our analysis has shown this could result in reduced future generation costs, due to geothermal generation being one of the most cost effective methods of producing electricity. A number of transmission and non-transmission options to remove the constraint have been assessed. The short listed options included: replace a 220/110 kv transformer at Kawerau (T12 or T13) with a higher rated unit; reconfigure the grid to connect part or all Matahina and Aniwhenua power station generation to Edgecumbe. We will not be able to replace a transformer before 2014 due to the lead time to procure and install it. Therefore, we have identified an interim, low-cost measure which will relieve constraints between the time the new Kawerau power station is commissioned and when we commission a new transformer. The interim measure is to connect one of the Matahina to Kawerau circuits directly to one of the Edgecumbe to Kawerau, bypassing Kawerau, to create a single circuit between Matahina and Edgecumbe. One Matahina generating unit will be connected to this new circuit, moving up to 40 MW of generation off the Kawerau 110 kv bus. Special protection schemes are required for this reconfiguration, and for all permanent options.. Typically these options cost between $5-7 million and are significantly less than the benefits investment will provide. In our Grid Investment Test analysis we considered these options across five different market development scenarios, each with different assumptions about generation development at Kawerau. The results show that replacing the Kawerau T12 transformer with a new unit rated at 250 MVA is the best option on average across the five market development scenarios, although the difference between options is very small. After further considering unquantified costs and benefits associated with each option it is our view that replacing Kawerau T12 with a 250 MVA transformer is the best option. In addition to being the most economic option from our Grid Investment Test analysis, it also provides the greatest number of unquantified benefits. It will provide additional capacity to encourage geothermal generation development and will capture some of the large benefits identified in our analysis in enabling geothermal development. It also provides a number of operational benefits, such as the capacity to perform some maintenance work without iii

3 disruption. The incremental cost of installing a 250 MVA transformer rather than a smaller 150 MVA transformer is also low (less than $1 million). As such the extra capacity is good value for money and may avoid the need to install another new transformer in the near future. Proposal at a Glance What: 1. Install a special protection scheme to manage loading on the Edgecumbe Owhata circuit and loading on the Kawerau interconnecting transformers as soon as practical 2. Reconfigure Kawerau Matahina circuit 2 and Edgecumbe Kawerau circuit 2 to bypass Kawerau substation as an interim measure as soon as practical 3. Procure and install a new 250 MVA transformer by 2014 to replace the Kawerau T12 transformer, install a special protection scheme to manage loading on the Edgecumbe Kawerau 1 and 2 circuits and undo the reconfiguration. When: Commence work in 2012 and complete in How much: Transpower is seeking approval for up to $ million This document is our formal submission to the Commerce Commission for approval to reconfigure circuits at Kawerau and then replace the Kawerau T12 transformer with a 250 MVA unit. 1 Our Maximum Approval Cost (MAC) is higher than the expected cost of the project as it includes an allowance for price uncertainties, project unknowns, is expressed in 2014 dollars and includes the financing costs associated with the proposed project. iv

4 Table of Contents 1 The need for investment The issue Options The options Analysis Benefits from investment Existing generation dispatch benefits Generation enabling benefits The cost of investment Investment Proposal Grid Investment Test Results Sensitivity of the results Unquantified costs and benefits Stakeholder engagement and submissions Approval Amount Appendices Glossary

5 1 The proposal This section describes our proposal. Components of the Proposal Installation of a special protection scheme to manage loading on the Edgecumbe Owhata circuit and loading on the Kawerau interconnecting transformers Reconfiguration of the Kawerau Matahina circuit 2 and Edgecumbe Kawerau circuit 2 to bypass Kawerau substation Procuring, installing and commissioning a new 250 MVA transformer to replace the Kawerau T12 transformer Installation of a special protection scheme to manage loading on the Edgecumbe Kawerau 1 and 2 circuits Decommisioning of the reconfiguration We propose starting this work in 2013 and completing it in We expect the project to cost $8.5 million once commissioned. However, we are seeking Commerce Commission approval to recover the full costs associated with the Proposal, upon commissioning, up to a total amount of $9.5 million. This amount includes a contingency to allow for uncertainties in the project costs and is the estimated Maximum Approval Cost to implement the Proposal. Please note that whilst we conducted the GIT analysis on an expected cost of $6.8 million, a subsequent cost review led to an increase to $7.2 million. This cost increase does not impact the GIT analysis since it is common to all options, nor does it affect the approval amount on which we consulted. 6

6 2 The need for investment A new geothermal power station (installed capacity of 25 MW) is being built at Kawerau and will be commissioned in December The amount of electricity that can be injected into the 110 kv bus at Kawerau is already constrained from time to time. The presence of the new generation will materially increase the amount of time that existing low fuel cost generation (hydro and geothermal) is constrained off at Kawerau and replaced with more expensive generation from elsewhere. We have identified a number of economic investments to relieve the generation constraint and enable further generation development. In this section we explain the need for investment. 2.1 The issue This investigation relates to our Kawerau substation. The current system is shown in Figure 2-1. Figure 2-1 System diagram Te Kaha Tarukenga 110 kv Okere Edgecumbe 110 kv 33 kv Waiotahi 110 kv 50 kv 11 kv Edgecumbe-Kawerau 110kV circuits Kawerau interconnecting transformers Owhata 110 kv 11 kv Kawerau 110 kv 220 kv 220 kv 11 kv 11 kv 11 kv (TASMAN) KAG Ohakuri 11 kv KEY 220kV CIRCUIT 110kV CIRCUIT 50kV CIRCUIT SUBSTATION BUS TRANSFORMER TEE POINT LOAD CAPACITOR GENERATOR Matahina 110 kv Aniwhenua There are a number of power stations that inject electricity into Kawerau substation: Mighty River Power s 105 MW geothermal power station Trustpower s 80 MW Matahina hydro station Todd Energy s 25 MW Aniwhenua hydro station. 7

7 Norske Skog Tasman Ltd plans to connect a further 25 MW of geothermal generation in December This will result in a total of 235 MW of generation being connected to our substation. Our grid does not have capacity to accept all this generation at times of low load at Kawerau. As a result, if additional capacity is not provided generation will need to be constrained off to manage loading on our equipment. Several industrial consumers are supplied via the Kawerau s 110 kv bus including Norske Skog Tasman Ltd, Carter Holt Harvey and SCA Hygiene. Figure 2-2 shows the 2010 load duration curve. In 2010 demand peaked at around 90 MW and averaged approximately 50 MW. Figure 2-2 Demand at Kawerau 110 kv bus MW Demand on Kawerau 110kV bus 2010 Halfhourly demand (sorted from top to bottom) Figure 2-3 shows the generation exported from the Kawerau 110 kv substation in Electricity is exported via the two 220/110 kv interconnecting transformers at Kawerau (T12 and T13) and the Edgecumbe Kawerau 110 kv circuits. With the commissioning of new generation the generation export line will move up, as shown in green. Figure 2-3 Generation export at Kawerau Generation Export at Kawerau 110kV Constrained generation MW With new Norkse Skog generation Halfhourly export (sorted from top to bottom) 8

8 The maximum amount of generation that could be exported from the Kawerau 110 kv bus by 2014 is around 148 MW. The area above the transmission limit, shown in red, represents constrained off generation. The quantum and duration of constrained off generation is highly dependent on hydrology. Aniwhenua and Matahina generation are likely to be constrained off more often in years where there are high inflows into the hydro catchments for the power stations. 9

9 3 Options In May we consulted on a long-list of options for relieving the generation constraint. A further two options were suggested by submitters during consultation and added to the long-list. The long list has been refined to a short list of five credible options to which we have applied the Grid Investment Test (GIT). Further details of the short listing process can be found in Attachment B The options The short list of options is shown in Table 3-1 below. Table 3-1 Credible Option List No. Option Description Cost ($000s) 0 Base Case Do Nothing 0 1 T12 150MVA Half reconfiguration the KAW T12 transformer with a 150MVA transformer 5,917 2 T12 250MVA Half reconfiguration the KAW T12 transformer with a 250MVA transformer 6,840 3 T13 150MVA 4 T MVA 5 Full reconfiguration Half reconfiguration the KAW T13 transformer with a 150MVA transformer Half reconfiguration the KAW T13 transformer with a 250MVA transformer Reconfigure the Edgecumbe-Kawerau 1&2 and Kawerau-Matahina 1&2 circuits EDG T4 transformer 100MVA 5,979 6,896 6,826 All new transformer options assume an interim half reconfiguration solution from The half reconfiguration will join the Edgecumbe Kawerau 2 and Kawerau Matahina 2 circuits together to bypass Kawerau substation. The output of one of the Matahina generating units flows directly on this new circuit to Edgecumbe. The Edgecumbe-Kawerau 1 circuit will be de-energised, The half-reconfiguration system configuration is shown in Figure 3-1. This solution is undone once a new transformer is commissioned at Kawerau in Our analysis has shown that with the constraint in 2013 the total cost of producing electricity would be approximately $0.7 million higher than if the half reconfiguration was in effect, based on an average hydro inflow year. The cost to install and then undo the half reconfiguration is estimated to be less than $0.6 million. Hence, it is economic to invest in the half reconfiguration, given it also manages the risk 10

10 associated with project delays and reduces production costs during sustained periods of high hydro inflows. The half reconfiguration has not been considered as a long-term solution by itself as it will not completely remove constraints, provides no additional capacity to enable future generation, and would necessitate the return to service of the Edgecumbe transformers. The full reconfiguration (Option 5) also requires that the Edgecumbe 220/110 kv interconnecting transformers be permanently returned to service 2. The Edgecumbe transformers are 59 years old and, if returned to service, the existing transformers would need to be replaced under the fleet strategy for older transformers around As such, this cost is associated with this option. For each option a number of special protection schemes are also required. These are protection schemes that monitor events on the system and automatically take action to ensure our assets are not overloaded. The accompanying Technical, Options and Costing report further describes these special protection schemes. It should be noted that the short list options represent the first stage of investment. As more generation is connected at Kawerau further investment will be required. This is discussed in more detail in Section 4.2. Figure 3-1 half-reconfiguration system configuration T4 Edgecumbe 110 kv 26 MW 10 MW EDG-WAI 2 Owhata Tarukenga 110 kv 110 kv OKE-TRK 1 Okere 110 kv EDG-OWH 1 OKE-OWH 1 OKE-TMI 1 Te Matai 110 kv EDG-KAW 2 KAW-MAT 2 KAW-MAT 1 Kawerau 220 kv EDG-KAW 3 36 MW 60 MW Matahina 110 kv 36 MW 36 MW MAT- G2 EDG-KAW 1 ANI- G1 T5 MAT-ANI 1 Edgecumbe 220 kv 24 MW 12 MW 12 MW ANI- G2 T MW KAG MAT- G1 139 MW 48 MW Aniwhenua 110 kv 25 MW NSK 100 MW T13 slack 8 MW Constraint KAW-OHK 1 Kawerau 110 kv 2 The Edgecumbe transformers are currently out of service (i.e. opened) to help maximise the amount of generation that can be exported from Kawerau. 11

11 4 Analysis 4.1 Benefits from investment The GIT requires us to determine the market benefits and costs of the base case and each of the upgrade options over five market development scenarios. We have assessed two key benefits of investing in the grid to enable unconstrained renewable generation: 1. Existing Generation Dispatch Benefits The existing generation dispatch benefits assume that no further generation connects to Kawerau after Norske Skog s new 25 MW plant. With no investment the existing renewable generation will at times be constrained off and more expensive generation elsewhere (e.g. gas turbines) will be dispatched in its place. The benefit is the difference in the production cost of electricity between doing nothing (base case) and investing to unconstrained dispatch. The first stage of all five development options provides sufficient capacity to remove the constraint. 2. Generation enabling benefits Generation enabling benefits arise from the reduction in the total capital cost of building and operating new generation across New Zealand by providing greater capacity for new generation to connect at Kawerau. If the total cost of building and operating new generation at Kawerau with no transmission constraint is lower than the total cost of building and operating new generation elsewhere, then there is benefit from investment in the Grid to relieve the transmission constraint at Kawerau. As new geothermal power stations currently represent one of the lowest cost means of generating electricity, this benefit is likely to be high. Our analysis includes an assessment of both the dispatch and enabling benefits arising from the short list options Existing generation dispatch benefits Without any transmission upgrade the existing generation at Kawerau (including Norske Skog Tasman s new 25 MW power station) will be constrained off at times resulting in more expensive generation being dispatched in its place. We have built a model utilising historical generation profiles, forecast demand profiles and the appropriate transmission capacity parameters to value this dispatch benefit by half-hour. The model calculates the amount of generation that is constrained for each year over the period from 2013 to It then multiplies the amount of generation constrained by the Short Run Marginal Cost (SRMC) of generation. A range of assumptions have been made in this calculation: 12

12 Matahina and Aniwhenua generation is based on the actual output in the 2005 year as this is considered an average inflow year, while Mighty River Power s geothermal generation is based on the 2009 year. New generation is assumed to have a similar half hourly relationship as Mighty River Power s geothermal generation. Local demand supplied via Horizon s distribution network is assumed to grow at 2% per annum. Forecast demand at Norske Skog Tasman is based on Norske Skog Tasman s advice regarding future projections of load at Kawerau. Norske Skog Tasman s peak demand tends to be in non-peak periods when wholesale market prices are lower. The existing generation at Kawerau comes from geothermal and hydro fuel sources. These forms of generation have a low marginal operating cost. With a constraint at Kawerau this low cost generation is likely to be replaced by more expensive thermal generation that requires burning gas and coal. Hence the constraint will result in higher production costs. To determine the additional production costs we have multiplied the amount of constrained off generation by the Short Run Marginal Cost (SRMC) of generation. The SRMC represents the cost of producing the last unit of electricity. It is our view that this approach is conservative, and using alternative methods, such as using Huntly s cost of production, would likely result in a higher benefit associated with removing the present constraint. We have calculated the SRMC for each of the five Market Development Scenarios (MDS) in the Electricity Commission s 2010 Statement of Opportunities 3 (SoO). Figure 4-1 illustrates the average annual SRMC that we have used to value constrained off generation by MDS. On average, values vary between $60/MWh to $180/MWh. 3 SRMCs were derived from modelling the SoO Scenarios using our modelling tool, SDDP. SDDP simulates the operation of the electricity market, over all historical inflow sequences. 13

13 Figure 4-1 Average short run cost of generation used to value constrained generation Average short run marginal cost of generation $/MWh MDS1 Sustainable path MDS3 Medium renewables MDS5 High gas discovery MDS2 South Island wind MDS4 Coal Under average hydro inflow conditions, around 20 GWh of generation would be constrained off each year with a value of $2 million per annum. Table 4-1 shows the net present value of the existing generation dispatch benefit arising from using the SRMCs from each MDS over the period. Table 4-1 Existing Generation Dispatch Benefit, NPV $ million MDS1 MDS2 MDS3 MDS4 MDS5 Average Benefit (in 2011 $) Generation enabling benefits The presence of generation constraints at Kawerau will provide a disincentive for new generation to locate behind the constraint. New generation in the area connecting behind the constraint would have to be prepared to either have output constrained some of the time or have to invest in transmission assets to enable connection to an unconstrained part of the network. There is a considerable benefit in investment to enable low-cost generation to connect at the Kawerau 110 kv bus given the potential for such low-cost renewable generation in the nearby area. To quantify this benefit, we have used five Market Development Scenarios (MDS) which are based on the MDS contained in the 2010 SoO but have been modified to: 14

14 account for 25 MW of new generation being built by Norske Skog which is not in any of the SoO scenarios. take into account the feedback from our May consultation that highlighted a number of potential new generators in the area over the coming 20 years. provide a greater range in the timing and size of new generation and hence make an assessment over a greater range of scenarios. The total amount of generation injecting into the 110 kv bus at Kawerau by MDS is shown in Figure 4-2 below. The majority of the new generation is assumed to be geothermal, and we have assumed that this generation has the generic capital cost of geothermal generation used in the SoO of $5,200/kW. Further detail on these MDS can be found in the Attachment B.. Figure 4-2 Total installed generation capacity at Kawerau by MDS Total Generation at Kawerau, MW MW MDS1 Sustainable path MDS3 Medium renewables MDS5 High gas discovery MDS2 South Island wind MDS4 Coal We have used the Electricity Authority s Generation Expansion Model (GEM), which is a least cost capacity expansion model of the New Zealand electricity sector, to calculate the benefit of enabling the generation. To calculate the benefit we have run the model twice for each MDS as follows: 1. assuming that generation expansion at Kawerau is unconstrained and is built as shown in Figure assuming generation expansion is constrained and only Norske Skog s new 25 MW generation plant is built. 15

15 The difference between the costs of generation expansion under these conditions gives us the benefit of enabling the generation shown in Figure 4-2. Table 4-2 presents the results. The results show the significant benefit that can arise from enabling lower cost renewable generation. Table 4-2 Generation enabling benefits, $ million 2011 MDS1 MDS2 MDS3 MDS4 MDS5 Average Enabling Generation Benefit MDS1 and MDS4 have the highest benefit due to the timing and size of the amount of generation that is enabled. In MDS5 only Norske Skog Tasman s new generation is built in both the constrained and unconstrained cases, hence there is no benefit. Intuitively, one would expect the benefit from MDS4 to be higher than MDS1 given there is more generation enabled under MDS4. However this is not the case since MDS4 assumes lower costs of thermal generation than MDS1 lessening the advantage of geothermal generation. 4.2 The cost of investment The cost of investment required to relieve constraints over an analysis period to 2034 will differ for each of the MDS. For example, to enable the generation in MDS4 both Kawerau T12 and T13 will eventually be replaced with larger units. Our analysis has focused on our 110 kv network as the constraints on this network arise first. Some additional investment may be required in our 220 kv network if a large power station is connected at Kawerau. Investigating these issues would significantly increase the scope of this investigation and is unlikely to alter our conclusions for investment at Kawerau as whatever is needed is likely to be common to all options over the analysis period. As noted in Section 2, the short list options represent the first stage of investment required to enable the generation in all of the MDS. In order to apply the GIT over the analysis period for each MDS, we have created a number of development plans, illustrated in Figure 4-3 below. 16

16 Figure 4-3 Development Plans The need and timing of the stages subsequent to stage 1 depends on the timing and amounts of future generation in each MDS. The development plans allow for sufficient transmission investment to be built to enable the generation in each MDS to be built without constraint 4. More information about the development plans are provided in the Attachment B. In some cases, if the incidence of constraint is minor, it may be economic to defer investment and incur a small constraint cost. Further, the full reconfiguration option results in reduced security and some small additional constraints associated with Matahina and Aniwhenua generation. Hence, for all options there is a minor constraint cost. We have also accounted for the need to replace assets due to age and condition. In particular, the full reconfiguration option would require the replacment of the Edgecumbe interconnecting transformers. With the other options this is deferred until significant amounts of additional generation appear at Kawerau. In the analysis it is assumed that if T12 (the younger transformer at Kawerau) is replaced then it could be moved to Edgecumbe to replace the existing interconnecting transformers saving the need to spend money on a new transformer. A 60 year replacement age has been assumed for the existing transformers at Kawerau. Table 4-3 and Table 4-4 show the total capital and constraint costs associated with the optimal development plan (including the cost of replacement of assets) for each option, by MDS. The figures shown in the table are present values and account for the timing of each subsequent investment that may be required. 4 Details of the optimal development plans for each scenario are contained in the accompanying Technical, Options and Costing document. 17

17 Table 4-3 Capital cost of optimal development plan, present value, $ million No. Option MDS1 MDS2 MDS3 MDS4 MDS5 Average Base Case Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full reconfiguration Table 4-4 shows the value of constraints associated with each of the options. These values are low. MDS1 has more constraints as the generation that is commissioned in the scenario is smaller and at some times it is more cost effective to delay investment and incur a small cost of constraint. Table 4-4 Constraint costs of optimal development plan, present value, $ million No. Option MDS1 MDS2 MDS3 MDS4 MDS5 Average Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full reconfiguration

18 5 Selecting the Investment Proposal Our investment proposal is option 2, the replacement of the T12 interconnecting transformer at Kawerau with a 250 MVA transformer. The benefits and costs for the options are very similar and it is not easy to differentiate between the options to identify the one that provides the best net benefit purely from the economic analysis. The replacement of Kawerau T12 with a new unit rated at 150 MVA (Option 1) is sufficient to reduce the level of constraint at Kawerau to an acceptable level following the commissioning of the new power station and is the lowest capital cost option. Our GIT analysis identified additional benefits from replacing T12 with a unit rated at 250 MVA (Option 2). The incremental cost of a larger unit is low (around $0.9 million). The benefits to New Zealand from investing to enable new low cost generation to connect at Kawerau ranges from $46-$193 million. If investing in additional capacity enabled only 5% of the lower bound of this benefit to be realised then a larger transformer may be associated with $2.3 million in additional benefits. This section details how Option 2 satisfies the Grid Investment Test and is also supported by our qualitative assessment of unquantified benefits. 5.1 Grid Investment Test Results Table 5-1 shows the expected net market benefit of each option relative to the base case averaged over all the MDS. The expected net market benefit is calculated as: the benefits from investment identified in Table 4-1 and Table 4-2 minus the capital cost of investment set out in Table 4-3, minus the constraint costs associated with investment shown in Table 4-4. Table 5-1: Expected Net Market Benefit (NPV $ million) No. Option Existing generation Dispatch Benefits (A) Enabling generation benefits (B) Transmission costs (C) Constraint Cost (D) Expected Net Market Benefit (A+B-C-D) Rank Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full

19 No. Option Existing generation Dispatch Benefits (A) Enabling generation benefits (B) Transmission costs (C) Constraint Cost (D) Expected Net Market Benefit (A+B-C-D) Rank reconfiguration The results show that replacing our T12 transformer at Kawerau with a 250 MVA transformer (Option 2) has the highest net market benefit. However, there is very little difference between options. The expected net market benefit of Option 2 is only $0.4 million higher than the lowest ranked option (full reconfiguration). 5.2 Results by Market Development Scenarios (MDS) Table 5-2 shows the expected net market benefit of each option for each MDS. Our proposal, Option 2 has the highest net market benefit in three of the five MDS. Only in the two scenarios with limited new generation, is it not the best option. The results also show that all options continue to give similar levels of benefit to each other across MDS. Table 5-2: Expected Net Market Benefit (NPV $ million) No. Option MDS1 MDS2 MDS3 MDS4 MDS5 Average Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full reconfiguration Sensitivity of the results We have re-run the analysis 5 to test the proposal s sensitivity to: capital costs demand growth discount rates Table 5-3 shows the expected net market benefit under this range of sensitivities. 5 In a commensurate manner, the years associated with each stage of the development plan for each option has not been reassessed for each sensitivity. 20

20 Our proposal, Option 2, returns the highest expected net market benefit in three of the six sensitivities. However, the table shows that all options retain a similar net market benefit to one another across the range of sensitivities. Table 5-3: Sensitivity results, Net market benefits, $ million No. Option -20% capital cost +20% capital cost Low demand High demand 4% discount rate 10% discount rate Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full reconfiguration It is our view that these results support our proposal and show it is robust. 5.4 Unquantified costs and benefits In order to further assist our decision making we have assessed the unquantified benefits for all options. Table 5-4 shows our qualitative assessment of the unquantified benefits of the different options. The benefit of each option has been qualitatively ranked between - and, with more ticks indicating a more favourable option. The following benefits have been considered: Operational benefits to what extent does the option provide operational benefits not reflected in the economic analysis? Installing a larger transformer is likely to provide operational benefits in that we will be able to perform some maintenance at the Kawerau substation without any need to constrain generation export. Option benefits does the option include flexibility to be amended in the future if there are significant changes and will it help enable further favourable benefits? All options allow a staged approach to future investments. In general, the full reconfiguration option may limit future options, either by way of using the Edgecumbe Kawerau circuits to supply new load in the region or by using the Edgecumbe interconnectors to connect other new generation in the wider region. Consumer benefits through enhanced competition to what extent will the option enhance competition in the New Zealand electricity market? 21

21 The more competitive a market is, the more efficient it will be at delivering the advantages that markets can provide to consumers. Consumer benefits are likely to be highest when installing a larger transformer which enables more renewable generation to be built. Minimises disruption to what extent will the local community be disrupted by the implementation of an alternative? All options are equal in this respect since the vast majority of the work will be carried out within the Kawerau substation. Some additional disruption may occur with the transformer options as outages will be required for the installation of the new transformer. Diversity benefits to what extent will the option provide diversity of supply? The full reconfiguration splits the system and improves system diversity by shifting generation to Edgecumbe. Table 5-4: Unquantified benefits No. Option ENMB Operational Option benefits Consumer Benefits Minimises Disruption Diversity benefits Overall Kawerau T MVA Kawerau T MVA Kawerau T MVA Kawerau T MVA Full reconfiguration T12 with a 250 MVA transformer outweighs other options as it allows minimum generation constraints for outages on the Edgecumbe Kawerau circuits and T13 transformer. Replacing T12 with a 250 MVA transformer allows for minimum generation constraints when T13 is to be replaced with a 250 MVA transformer as more generation connects onto Kawerau. This option provides Transpower the flexibility in the future to either increase the interconnection capacity at Kawerau or shift some generation to Edgecumbe as more generation development appears. Our qualitative assessment of the non quantified benefit supports the option which passes the GIT, namely Option 2 the interim half reconfiguration as soon as possible followed by a new 250 MVA to replace Kawerau T12 transformer in

22 6 Stakeholder engagement and submissions We have engaged with stakeholders on two occasions. The overall theme of all the submissions was supportive and positive. 6.1 Request for Information In May 2011 we released an Options, Assumptions, Approach and Request for Information document. In response, we received eight submissions: Eastland Generation Limited Bay of Plenty Energy/TrustPower (joint submission) Horizon Energy Bay of Plenty Regional Governance Group Norske Skog Tasman Limited Mighty River Power Kawerau District Council Ngati Tuwharetoa Holdings Ltd In general the submissions stressed the need to remove the constraint on generation for commercial, economic and regional development reasons. The submissions highlighted the number of new generation opportunities being considered in the Kawerau area. This feedback was incorporated into our analysis through amendments to the market development scenarios. Further a number of alternative options were raised during this consultation and this feedback helped us to develop the full and half reconfiguration short listed options. 6.2 Consultation on our application of the Grid Investment Test In November 2011 we released the results from our application of the Grid Investment Test which showed that our preferred upgrade option was to half reconfigure the grid at Kawerau as soon as possible and then replace the T12 transformer at Kawerau with a 250 MVA transformer in 2014 (with associated Special Protection Schemes). During the consultation. we ran a forum at Tauranga that was attended by 10 stakeholders. At the forum we presented the results from our analysis and clarified any matters arising from the consultation material. During the consultation we requested feedback on our application of the Grid Investment Test. Overall industry stakeholders believe that we have reasonably applied the GIT. and we do not consider any of the issues that were raised impact on the conclusions presented in the consultation material. 23

23 Full details of the consultation can be found in Attachment C.. 24

24 7 Approval Amount If a project is approved by the Commerce Commission, we can recover the costs of the project through the regulated charges for the transmission grid. The Commerce Commission also approves an amount that we can spend. If we spend under this amount, we only recover actual costs. Our investment proposal is to Install a special protection scheme to manage loading on the Edgecumbe Owhata circuit and loading on the Kawerau interconnecting transformers as soon as practical; Reconfigure Kawerau Matahina circuit 2 and Edgecumbe Kawerau circuit 2 to bypass Kawerau substation as soon as practical; Procure and install a new transformer rated at 250 MVA by 2014 to replace Kawerau T12, install a special protection scheme to manage loading on the Edgecumbe Kawerau 1&2 circuits and undo the reconfiguration. We determine an approval amount by accounting for the uncertainties in the project cost to calculate a Maximum Approval Amount (MAC). The Expected Cost of the investment proposal is estimated to be $7.2 6 million and the MAC is estimated to be $9.5 million. As we recover the costs once the project is commissioned (completed), the approved amount from the Commerce Commission is expressed in commissioning year dollars. Also included in the expected cost is an amount for our Community Care funding. Transpower acknowledges that while there are clear benefits from electricity transmission, our work will impact on local communities. In summary, the MAC is higher than the Expected Cost because it: includes an allowance for price uncertainties, and project unknowns. is expressed as 2014 dollars not 2011 covers all the financing costs associated with the proposed project. This is shown in Table Please note that whilst we conducted the GIT analysis on an expected cost of $6.8 million, a subsequent cost review led to an increase to $ million. This cost increase does not impact the GIT analysis since it is common to all options, nor does it affect the approval amount on which we consulted. 25

25 Table Approval Amount Expected Cost ($ million, 2011) Including Price Uncertainty ($ million, 2011) Including Inflation to 2014 ($ million, 2014) Including Financing Costs - MAC ($ million, 2014)

26 8 Attachments Further information is contained in the following attachments: Attachment A Meeting the requirements of the Rules Attachment B Technical, options and costing report Attachment C Summary of submissions and response to submissions 27

27 Glossary Term Alternative Project Economic Investment GEM Grid Investment Test (GIT) Grid Modelled project Description Limited to those appropriate in number and technology given the cost magnitude of the proposed investment, the complexity of the modelling and the urgency of the proposed investment. Likely to proceed if neither the proposed investment nor any other alternative project proceeds and unlikely to proceed if the proposed investment does proceed. Reasonably expected to provide similar benefits in type but not necessarily magnitude to relevant nodes as the proposed investment (Schedule F4 clauses 11 and relevant part of clause 19). Investments in the grid that can be justified on the basis of the Grid Investment Test set out at Schedule F4. Generation Expansion Model is a capacity expansion model of the New Zealand electricity sector developed by the Electricity Commission and Electricity Authority. A test for reliability investments and economic investments in the grid The system of transmission lines, substations and other works used to connect grid injection points and grid exit points to convey electricity throughout the North and South Islands of New Zealand A modelled project is a project which is not part of the proposal, but is likely to occur in one or more scenarios within the time horizon of the analysis. Schedule F4 (Grid Investment Test) SDDP Statement of Opportunities (SoO) Transmission Alternatives Authorised under the Commerce Act section 54R. Stochastic Dual Dynamic Programme developed by Power Systems Research in Brazil. It is used to assess national generation costs based on a distribution of hydro inflows into storage lakes across various generation scenarios. Statement of Opportunities developed by the Electricity Commission (EC). The EC has been disestablished and the 2010 SoO is the last. Alternatives to investment in the grid, including investment in local generation, energy efficiency, demand-side management and distribution network augmentation 28