Draft Project Assessment Report. Dromana Supply Area. Project UE-DZA-S RIT-D Report

Transcription

1 Draft Project Assessment Report RIT-D Report This report presents the network limitations at Dromana zone substation and the distribution feeder network within the Dromana / Mornington supply areas, including the preferred option to address those limitations.

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3 Table of Contents 1 Approval and Document Control 4 2 Executive summary 5 3 Introduction 13 4 Identified Need Network overview Description of the identified need Insufficient zone substation capacity Insufficient load transfer capability High distribution feeder utilisation Poor distribution feeder reliability performance Closing comments on the need for investment Quantification of the identified need 20 5 Key assumptions in relation to the identified need Forecast maximum demand Zone substation Distribution feeders Expected unserved energy Characteristic of load profile Load transfer capacity and supply restoration times Plant failure rates Discount rates Plant ratings Value of customer reliability 27 6 Summary of submissions 28 7 Credible options included in this RIT-D 29 8 Market modelling methodology Classes of market benefits considered Changes in involuntary load shedding Changes in load transfer capability Changes in network losses Classes of market benefits not expected to be material Changes in voluntary load shedding Changes in costs to other parties Difference in timing of distribution investment 34 Page 2 of 53

4 8.2.4 Option value Quantification of costs for each credible option Scenarios and sensitivities Demand forecasts Capital costs Value of customer reliability Discount rates Average Victorian spot price Summary of sensitivity testing 36 9 Results of analysis Gross market benefits Key categories of market benefits Net market benefits Sensitivity and scenario assessment Economic timing Proposed preferred option Submission Request for submission Next steps Checklist of compliance with NER clauses Abbreviations and Glossary 49 Appendix A 52 Page 3 of 53

5 1 Approval and Document Control VERSION DATE AUTHOR 1 31 July 2014 UE Network Planning Amendment overview New document Page 4 of 53

6 2 Executive summary Purpose This Draft Project Assessment Report has been prepared by United Energy (UE) in accordance with the requirements of clause (j) of the National Electricity Rules (NER). The purpose of this report is to provide a basis for consultation on the proposed preferred option to address the network limitations within the Dromana supply area. 1 This report has been prepared following the conclusion of consultation on the Non Network Options Report (NNOR), which represents the first stage of the consultation process in relation to the application of the RIT-D. This report: Describes the need which UE is seeking to address, together with the assumptions used in identifying that need. Summarises and provides commentary on the submission(s) received on the NNOR. Describes the credible options that are considered in this RIT-D assessment. Describes the methods used in quantifying each class of market benefit. Quantifies costs (with a breakdown of operating and capital expenditure) and classes of material market benefits for each of the credible options. Provides reasons why differences in changes in voluntary load curtailment, costs to other parties, option value and timing of other distribution investment do not apply to a credible option. Provides the results of NPV analysis of each credible option and accompanying explanatory statements regarding the results. Identifies the proposed preferred option, which is the installation of the second DMA transformer plus two new distribution feeders and reconfiguration of the existing DMA distribution network. The need for investment Dromana (DMA) zone substation was commissioned in March 2006, as a single transformer zone substation, to provide load relief to neighbouring Mornington (MTN) and Rosebud (RBD) zone substations. From inception, DMA has showed a steady growth in maximum demand, with the actual summer maximum demand in exceeding the nameplate rating of the transformer. Based on the current load forecast, the 10% PoE summer maximum demand at DMA is expected to exceed the station s N cyclic rating in summer Given DMA is a single transformer zone substation, customers supply is normally restored via the distribution feeder network from neighbouring zone substations at MTN and RBD, following the loss of the zone substation transformer or other fault resulting in the total loss of supply to DMA. Due to on-going customer load growth, the spare capacity in the neighbouring network during high 1 NER: clause (k) Page 5 of 53

7 Expected customer value of lost load ($,000) demand periods has diminished below the summer maximum demand at DMA. As a consequence, some customers could potentially be without electricity supply until the capacity in the neighbouring network becomes available. Based on the current load forecast, some customers are expected to be without electricity supply from summer , following the loss of the transformer during high demand. The distribution network from DMA zone substation is characterised by relatively long distribution feeders. As a result, a number of distribution feeders within the DMA supply area have shown poor reliability performance compared to the overall UE network. In addition a number of distribution feeders in the DMA and MTN supply areas are forecast to exceed their thermal capability within the next five years. The forecast impact of the identified need discussed above is presented in Figure 1. Figure 1 Forecast impact of the identified need Results of consultation on options On 28 March 2014, UE published the NNOR providing details on the network limitations within the Dromana supply area. This report sought information from Registered Participants and Interested Parties regarding alternative potential credible options or variants to the potential credible options presented in that report. In response to the report, UE received enquiries from several non-network service providers. UE took this opportunity to further populate its Demand Side Engagement Register 2 and engaged in joint planning with those proponents to assess the viability of alternative credible options within the 2 UE has established a Demand Side Engagement Register for industry participants, customers, interest groups and non-network service providers who wish to be regularly informed of our planning activities. Page 6 of 53

8 Dromana supply area. UE received two submissions by 20 June 2014, being the closing date for submissions to the NNOR. Both submissions indicated that there are no identified credible alternative options within the Dromana supply area. Credible options for addressing the identified need UE presented seven long term options in the NNOR. Five of these options were regarded as not being credible for reasons set out in that paper. Given there are no identified credible alternative solutions with the Dromana supply area, only two credible options have been considered for further detailed study and application of the RIT-D. Table 1 Credible options considered in the RIT-D Option Option 1 Option 2 This option includes: Description Installing a new 20/33 MVA 66/22 kv transformer at Dromana zone substation. Extending the 22 kv busbar at Dromana zone substation. Developing two new 22 kv distribution feeders to supply the existing loads in and around Dromana area. The estimated total cost, inclusive of operating costs, is estimated at $8.4 million (in PV terms) This option includes: Installing a new 20/33 MVA 66/22 kv transformer at Mornington zone substation. Developing three new 22 kv distribution feeders at Mornington zone substation to supply the existing loads in and around Dromana area. Developing one new 22 kv distribution feeder at Rosebud zone substation to supply the existing loads in and around Dromana area. The estimated total cost, inclusive of operating costs, is estimated at $17.3 million (in PV terms) The purpose of the RIT-D is to identify the preferred option that maximises the present value of net market benefit to all those who produce, consume and transport electricity in the National Electricity Market (NEM). 3 In order to quantify the net market benefits of each credible option, the expected unserved energy under the base case (where no action is taken by UE) is compared against the expected unserved energy with each of the credible option in place. Scenarios considered The NER stipulates that the RIT-D must be based on cost-benefit analysis that considers a number of reasonable scenarios of future supply and demand. 4 In this particular RIT-D, UE notes that different assumptions regarding future supply or transmission development are not expected to impact on the assessment of alternative options. In order to define reasonable scenarios, UE examined the sensitivity of net market benefits to a change in key input variables or value within the base (expected) estimates that drive market benefits. Table 2 below lists the variables and respective ranges adopted for the purpose of defining reasonable scenarios. 3 AER: Regulatory Investment Test for Distribution Application Guidelines, Section 1.1. Available 4 NER: clause (c) paragraph 1 Page 7 of 53

9 Table 2 Variables and ranges adopted for the purpose of defining scenarios Variable for sensitivity testing Lower bound Base case Upper bound Maximum demand Low (Base estimates minus 5% per annum off the total forecast demand at DMA) 5 Base estimates N/A Capital costs Low (Base estimates minus 10%) Base estimates High (Base estimates plus 10%) Value of customer reliability Low (Base estimates minus 15%) Base estimates High (Base estimates plus 15%) Discount rate 8.5% 9.5% 10.5% Average Victorian Spot Price Low (Base estimates minus 15%) Base estimates High (Base estimates plus 15%) The sensitivity assessment indicated that the net market benefit of each credible option was most sensitive to changes in: Demand levels; Value of customer reliability; Discount rate; and Cost of investment. Accordingly, UE has defined twelve scenarios to test the robustness of this RIT-D assessment: the base case (or the most likely scenario), and eleven other scenarios which represent plausible combination of upper and lower bound assumptions on the key variables of demand growth, investment cost, value of customer reliability and discount rate. Table 3 Reasonable scenarios under consideration Scenario Demand growth VCR Investment cost Discount rate Base case Base Base Base Base Scenario 1 Base Low Base Base Scenario 2 Base Low High Low Scenario 3 Base Low High High Scenario 4 Base High Base Base Scenario 5 Base High Low Low Scenario 6 Base High Low High 5 This is equivalent to 2-3 MW per annum lower than the base (expected) forecast at DMA. Page 8 of 53

10 Scenario Demand growth VCR Investment cost Discount rate Scenario 7 Low Base Base Base Scenario 8 Low Low Base Base Scenario 9 Low Low High Low Scenario 10 Low High Base Base Scenario 11 Low High Low Low NPV Results Table 4 sets out a comparison of the present value of net market benefits of each option under all reasonable scenarios, over a twenty-year period. The shaded cell in each row indicates the option that maximise the net market benefit for that particular scenario relative to Do nothing. Table 4 Net market benefits of each credible option under various scenarios (PV, $m) Scenario Net Market Benefit Do Nothing Option 1 Option 2 Ranking Net Market Benefit Ranking Net Market Benefit Ranking Base case Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario (1.58) 3 Scenario (1.45) 3 Scenario Scenario Page 9 of 53

11 The results set out in table above show: Option 1 maximises net market benefit under the base case set of assumptions; Option 1 maximises net market benefit under all scenario analysis involving the variation of assumptions within plausible limits. Option 2 is found to have negative market benefit in majority of the scenario analysis, when the demand at DMA is 5% less than forecast. As a consequence, this option is ranked lower than the Do Nothing option. This RIT-D assessment demonstrates that Option 1 maximises the present value of net market benefits under all reasonable scenarios considered. The preferred option for investment is therefore Option 1: Installation of the second DMA transformer plus two new distribution feeders and reconfiguration of the existing DMA distribution network. This option satisfies the requirements of the RIT-D. Although the choice of the proposed preferred option is clear, the timing of this investment is not, given a number of reasonable scenarios are investigated. The economic timing of the proposed preferred option is when the annualised cost of power supply interruption exceeds the annualised cost of the proposed preferred option. Table 5 below shows the expected timing of the proposed preferred option under each reasonable scenario. Table 5 Expected timing of the proposed preferred option Scenario Timing Base case Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Page 10 of 53

12 The results set out in table above show that: The timing of the proposed preferred option is under the base case reasonable scenario (i.e. under the most likely scenario). There may be scope for deferring the proposed preferred option by one year if: o The value of customer reliability is 15% lower than the base estimates. There may be scope for deferring the proposed preferred option by two years if: o The maximum demand at DMA is 5% per annum lower than base estimates that is, the maximum demand at DMA is approximately 2-3 MW per annum lower than the forecast. The proposed preferred option may be implemented earlier if: o The VCR is 15% higher than the base estimates. Recommendation The recommended action involves: Installation of a new 20/33 MVA 66/22 kv transformer at Dromana zone substation. Extension of the 22 kv indoor bus at DMA with: o o o o One 22 kv transformer circuit breaker Four 22 kv feeder circuit breakers One 22 kv capacitor circuit breaker One 22 kv bus-tie circuit breaker Upgrade of existing protection and control schemes. Development of two new 22 kv distribution feeders to supply the existing load in and around the Dromana area, including rearrangement works. The total project cost, inclusive of operating costs, is estimated at $8.4 million (in present value terms). While the timing of the base case scenario is indicating a commissioning, it may not be physically possible to complete works by this time. Therefore the expected commissioning date of this option is no later than December 2016 which is consistent with the one-year deferral scenarios identified above. Page 11 of 53

13 Next steps UE invites written submission on this report from registered participants and interested parties. All Submissions and enquiries should be directed to the United Energy Manager Network Planning at Submissions are due on or before 26 September All submissions will be published on UE website. 6 Following UE s consideration of the submissions, the preferred option including the expected commissioning date, and a summary of, and commentary on, the submissions received to this report will be included as part of the Final Project Assessment Report (FPAR). This report represents the third and final stage of the consultation process in relation to the application of the RIT-D. UE intends to publish the Final Project Assessment Report in November If you do not want your submission to be publically available, please clearly stipulate this at the time of lodgement. Page 12 of 53

14 3 Introduction This Draft Project Assessment Report has been prepared by United Energy (UE) in accordance with the requirements of clause (j) of the National Electricity Rules (NER). This report represents the second stage of the consultation process in relation to the application of the Regulatory Investment Test for Distribution (RIT-D) for addressing capacity limitations at Dromana (DMA) zone substation and its distribution feeder network. In March 2014, UE published the first stage of the RIT-D, being the release of the Non Network Options Report (NNOR). This report sought information from Registered Participants and Interested Parties regarding alternative potential credible options or variants to the potential credible options presented in that report. In response to the report, UE received two submissions; both indicating that there are no credible alternative options within the Dromana supply area. This report: Provides background information on the network limitations at DMA zone substation. Describes the need which UE is seeking to address, together with the assumptions used in identifying that need. Summarises and provides commentary on the submission(s) received on the NNOR. Describes the credible options that are considered in this RIT-D assessment. Quantifies costs (with a breakdown of operating and capital expenditure) and classes of material market benefits for each of the credible options. Describes the methods used in quantifying each class of market benefit. Provides reasons why differences in changes in voluntary load curtailment, costs to other parties, option value and timing of other distribution investment do not apply to a credible option. Provides the results of NPV analysis of each credible option and accompanying explanatory statements regarding the results. Identifies the preferred option, including detailed characteristics, estimated commissioning date, indicative costs and noting that it satisfies the RIT-D. The contact detail of UE staff member to send queries on this RIT-D. Page 13 of 53

15 4 Identified Need 4.1 Network overview Dromana (DMA) zone substation is equipped with one 20/33 MVA 66/22 kv transformer and provides electricity supply to approximately 15,000 customers. The areas supplied include Dromana, Mount Martha, Red Hill and Shoreham as illustrated in the map below. Figure 2 Geographical areas supplied by DMA zone substation DMA zone substation was commissioned in March 2006 to: Off-load Mornington (MTN) and Rosebud (RBD) zone substations; Off-load distribution feeders; and Improve supply reliability in the area. Page 14 of 53

16 Figure 3 below presents the Single Line Diagram of DMA zone substation depicting the present configuration. Figure 3 Existing configuration of DMA (schematic view) DMA zone substation is supplied via two 66 kv sub-transmission lines, one from Tyabb Terminal Station (TBTS) and the other from MTN zone substation. There are also two out-going 66 kv subtransmission lines that supply RBD and then Sorrento (STO) zone substations in the lower Mornington Peninsula. Ring bus configuration at DMA prevents a single sub-transmission line fault tripping the zone substation transformer. However, a forced outage of the zone substation transformer, the 22 kv bus, the incomer cable or the incomer circuit breaker would result in the loss of the zone substation transformer (i.e. total loss of supply from DMA zone substation). Following such an event, customers supply is restored (in part) via the distribution feeder network from neighbouring zone substations at MTN and RBD. Whilst the probability of a transformer outage or other fault resulting in the total loss of supply to DMA is very low, the energy at risk 7 resulting from the total loss of supply of the zone substation is high because customers supplied from DMA zone substation are exposed to such an event all year round, not just during periods of high demand. 7 Energy at risk is the amount of energy that would not be supplied due to a major outage of the DMA zone substation transformer. Page 15 of 53

17 Load (MW) 4.2 Description of the identified need Insufficient zone substation capacity DMA is a summer critical zone substation. The figure below depicts the historical actual and weather corrected maximum demands, 10% and 50% PoE maximum demand forecasts together with the station s operational ratings. Figure 4 Forecast maximum demand against station ratings for DMA zone substation DMA Summer Maximum Demand Year Actual Load 10% PoE Forecast (MW) 50% PoE Forecast (MW) Summer (N-1) Rating Summer (N) Rating (MVA) Nameplate Rating (MVA) Weather corrected actuals As illustrated above: The historic actual maximum demand at DMA zone substation has been above its nameplate rating since summer The 10% PoE maximum demand 8 at DMA zone substation is expected to exceed the station s (N) cyclic rating in summer , for about 1 hour. In other words, at the 10% PoE maximum demand at DMA, and in the absence of any mitigation action: Inadequate capacity at the station would be expected to lead to supply interruption from summer , under system normal conditions (i.e. with all plants in service). 8 This forecast is also referred to as having a 10% probability of exceedance. It represents a forecast that is expected, on average, to be exceeded once in ten years. Page 16 of 53

18 4.2.2 Insufficient load transfer capability Following a major outage of the transformer at DMA zone substation, customers supply can be restored (in part) via the distribution network from neighbouring zone substations at MTN and RBD. At present, limited load transfer capability exists between DMA and neighbouring network during high demand periods. As a result, some customers could potentially be without electricity supply until the capacity in the neighbouring network becomes available. With increasing demand, the available load transfer capability diminishes, leaving greater numbers of customers exposed to risk of supply interruption as shown in table below. Table 6 Forecast load at risk 10% PoE conditions 50% PoE conditions Year Demand 9 (MW) Transfer Capability (MW) Load at Risk 10 (MW) Demand 9 (MW) Transfer Capability (MW) Load at Risk 10 (MW) As shown above: The load transfer capability away from DMA is less than that required to fully restore DMA load following the loss of the zone substation transformer (i.e. N-1) at maximum demand, for about 64 hours (at 10% PoE demand conditions). In other words, an outage of the DMA zone substation transformer at maximum demand, and in the absence of any mitigation action: Inadequate load transfer capability between DMA and neighbouring network is expected to lead to supply interruptions from summer The maximum demand forecasts are based on the medium (base) economic growth scenario. 10 Load at risk is the amount of load that would not be supplied due to a major outage of the DMA zone substation transformer. These numbers reflect the impact of load transfer capability. Page 17 of 53

19 Utilisation (%) High distribution feeder utilisation Utilisation of critical distribution feeders within the DMA, MTN and RBD supply areas are presented in Figure 5. Utilisation describes the ratio of the feeder maximum demand to the summer cyclic rating (N) under normal operating conditions. Figure 5 Feeder utilisation in summer (10% PoE maximum demand) Distribution feeder utilisation in summer % 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% DMA 12 DMA 14 MTN 21 MTN 23 MTN 31 MTN 34 MTN 35 RBD 21 RBD 23 As illustrated above: The loading on DMA 12 is forecast to exceed its cyclic rating in summer The loading on MTN 35 is forecast to be 99% utilised in summer The loading on MTN 23 is forecast to be 93% utilised in summer Emerging capacity limitations in distribution feeders are managed by transferring load away to neighbouring feeders at maximum demand. For instance, some load can be transferred away from DMA 12 to MTN 31. Such actions are adopted usually as the initial mitigation action due to its low upfront cost. However, such an option cannot be sustained in the future, as the spare capacity in the neighbouring feeders have depleted due to on-going customer load growth and load transfers in the past to manage high utilisation in the area. Page 18 of 53

20 4.2.4 Poor distribution feeder reliability performance The distribution network from DMA zone substation is characterised by relatively long distribution feeders. As a result, they have shown poor reliability performance compared to the overall UE network. More specifically, DMA 13 and DMA 14 are amongst UE s top ten rogue feeders as shown in Table 7. Table 7 Ranking of DMA feeders relative to UE network in 2013 (calendar year) Feeder UE poor reliability ranking for Feeder length (km) Customer numbers DMA 11 > ,143 DMA ,045 DMA ,793 DMA ,070 DMA 15 > ,732 With increasing customer numbers, the adverse impact of these feeders on the overall reliability performance of the UE network is expected to increase over time as the rate of customer growth is higher than the UE average. 4.3 Closing comments on the need for investment The following limitations are to be addressed by this RIT-D: From summer , inadequate load transfer capability between DMA and the neighbouring network is expected to lead to supply interruption, following the loss of the DMA zone substation transformer at maximum demand; From summer , inadequate capacity at DMA zone substation is expected to lead to supply interruption, under system normal conditions (i.e. with all plants in service) for a one-in-ten year summer; A number of distribution feeders in the DMA and MTN supply areas are forecast to exceed their thermal capability within the next five years; and A number of distribution feeders within the DMA supply area have shown poor reliability performance. In light of the growing demand at DMA and the forecast increase in load at risk, UE has examined a number of options to alleviate the identified need. These options were outlined in the NNOR. The credible options identified for further detailed study and application of the RIT-D are presented in Section From a total UE distribution feeder count of approximately 430 feeders. Page 19 of 53

21 4.4 Quantification of the identified need The forecast impact of the identified need discussed in Section 4.2 is presented in Table 8. The table shows: Load at risk, which is the MW load shedding required to avoid the network limitation under the 10% PoE maximum demand forecast. This reflects the reduced impact because of load transfer capability. Customer value of lost load is the cost of the expected unserved energy, obtained by multiplying the expected unserved energy 12 by the Value of Customer Reliability (VCR) using a detailed assessment of the risk which includes consideration of the load transfer capability. Table 8 Forecast network limitation Year Load at Risk 13 (MW) Customer Value of Lost Load ($,000) , , , , , , , The expected unserved energy is the portion of the energy at risk after taking into account the probability of an outage of critical plants, combined with a 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand (see Section 5.2). 13 The load at risk includes both pre-contingent and post-contingent load reduction requirements. Page 20 of 53

22 Maximum demand (MW) 5 Key assumptions in relation to the identified need 5.1 Forecast maximum demand Zone substation Forecasts of the 10% PoE and 50% PoE summer maximum demand at DMA, MTN and RBD zone substations are presented in Figure 6 and Figure 7 below. These forecasts are based on the base (expected) economic growth scenario. Figure 6 10% PoE summer maximum demand forecasts at DMA, MTN and RBD zone substations Forecast 10 % PoE summer maximum demand MTN RBD DMA Page 21 of 53

23 Demand (MW) Figure 7 50% PoE summer maximum demand forecasts at DMA, MTN and RBD zone substations Forecast 50% PoE summer maximum demand MTN RBD DMA Distribution feeders Average annual growth in summer maximum demand of the distribution feeders in the DMA, MTN and RBD supply areas are presented in Table 9. Table 9 Annual growth rate of distribution feeders Distribution feeders Annual growth rate at 10% PoE Annual growth rate at 50% PoE DMA 4.0% 3.9% MTN 3.1% 3.0% RBD 2.1% 2.0% Average UE growth rate (for comparison) 1.7% 1.4% Page 22 of 53

24 Normalised Load (%) 5.2 Expected unserved energy For the purpose of undertaking the RIT-D, the amount of expected unserved energy was estimated by taking 30% weighting of the unserved energy at 10% PoE maximum demand forecast and 70% weighting of the unserved energy at 50% PoE maximum demand forecast Characteristic of load profile DMA zone substation provides electricity supply to approximately 15,000 customers in the areas of Dromana, Mount Martha, Red Hill and Shoreham. The zone substation load is characterised primarily of residential loads with commercial and light industrial loads in the major population centres. The peak demand occurs during summer holiday periods as illustrated in Figure 8. Figure 8 Load profile at DMA zone substation ( ) Load Profile 120% 110% 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Winter Spring Summer Autumn Hours A typical load profile on the day of summer maximum demand is presented in Figure 9. Normally, the electricity demand at Dromana remains relatively low during the day, with a large increase in demand during the late afternoon to early evening hours. 14 This approach accounts for uncertainty in the demand forecast and is consistent with the approach undertaken by AEMO for estimating the expected unserved energy. Page 23 of 53

25 Proporation of maximum demand 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Normalised Load (%) Figure 9 Load profile on day of summer maximum demand at DMA zone substation Daily peak load profile 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Time of day Figure 10 shows the normalised load duration curves at DMA zone substation for the last five summers. Figure 10 Historical load duration curves at DMA zone substation Load duration curve 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Proportion of time Page 24 of 53

26 The figure above shows that that the load characteristics can vary from year to year. It also shows that around 40-50% of the maximum demand lasts less than ten per-cent of the period. This implies that although the probability of reaching high demand levels is reasonably low, the impact of not having sufficient capacity can result in significant amount of load at risk. To account for variability in load characteristics, UE has prepared load traces based on historical load traces that characterised: 10% PoE and 50% PoE demand profiles (or close to) for DMA zone substation; Maximum demand occurring during summer holiday periods; and Excluded load transfer from / to neighbouring network. Based on this approach, the expected unserved energy at DMA zone substation was estimated using the expected and historical traces. The above-mentioned approach was adopted to estimate the expected unserved energy at MTN and RBD zone substations. The MTN and RBD load traces were therefore based on the following base years: Table 10 Base years used to develop load traces Zone substation Base year 10% PoE load trace Base year 50% PoE load trace DMA MTN RBD Load transfer capacity and supply restoration times The load transfer capability between DMA and neighbouring network was calculated for summer , as part of UE s contingency planning studies. Future load transfer capability between DMA and neighbouring network were estimated by reducing the load transfer capability in by the annual growth rate of MTN and RBD distribution feeders that are used to restore DMA load, following an outage of the DMA zone substation transformer. For the purpose of this RIT-D, the customers supply is restored within 60 minutes following the loss of a major plant (i.e. zone substation transformer / distribution feeders). This figure represents UE s current reliability performance target for CAIDI The historic load trace characterised (or close to) a 50% PoE maximum demand profile at DMA. 16 The historic load trace characterised (or close to) a 10% PoE maximum demand profile at DMA. 17 CAIDI represents the average restoration time for each outage. Page 25 of 53

27 5.5 Plant failure rates The base (average) reliability data adopted in this assessment are presented in tables below. The data is derived from the Australian CIGRE Transformer Reliability Survey carried out in 1995 and UE s observed network performance since Table 11 Summary of transformer outage rates Major plant item: zone substation transformer Interpretation Transformer failure rate (major fault) Duration of outage (major fault) Transformer failure rate (minor fault) Duration of outage (minor fault) 0.5% per annum 2190 hours 1.0% per annum 48 hours A major failure is expected to occur once per 200 transformer-years. A total of 3 months is required to repair / replace the transformer, during which time the transformer is not available for service. A minor failure is expected to occur once per 100 transformer-years. A total of 48 hours is required to repair the transformer, during which time the transformer is not available for service. Table 12 Summary of distribution feeder outage rates Major plant item: distribution feeder Interpretation Distribution feeder failure rate per km (major fault) Duration of outage (major fault) 7 faults per 100 km per annum 4 hours The average sustained failure rate of UE s distribution feeder is 7.0 faults per 100 km per year. A total of 4 hours is required to repair / replace the feeder (or sections of feeder), during which time the feeder (or sections of the feeder) is not available. Table 13 Summary of other plant outage rates Equipment Outage rate Outage duration 22 kv bus (major fault) 22 kv circuit breaker (minor fault) 2% per annum 3 months 0.3% per annum 24 hours 5.6 Discount rates To compare cash flows of options with different time profiles, it is necessary to use a discount rate to express future costs and benefits in present value terms. The choice of discount rate will impact on the estimated present value of net market benefits, and may affect the ranking of alternative options. A real, pre-tax discount rate of 9.5 per-cent is adopted in this assessment. Page 26 of 53

28 5.7 Plant ratings The station ratings of DMA, MTN and RBD are limited by the thermal capability of the zone substation transformers. The transformer summer cyclic ratings are calculated based on ambient temperature of 40 C and corresponding load profiles at respective zone substations. The transformer winter cyclic ratings are based on 10 C ambient temperature. The distribution feeder ratings are calculated based on ambient temperature of 40 C. In addition to temperature, overhead line ratings are based on solar radiation of 1000 W/m 2 and a wind speed of 3 m/s at an angle to the conductor of 15 (i.e. an effective transverse wind speed of 0.78 m/s), while the underground cable ratings are based on soil thermal resistivity of 0.9 Cm/W or 1.2 Cm/W at specific sites. For underground cables, a typical load profile has been considered to accommodate the variability in demand over time. Summer and winter ratings of corresponding zone substation transformers are presented in table below. Table 14 Summary of transformer cyclic ratings (MVA) Zone substation Summer cyclic rating at 40 C Winter cyclic rating at 10 C N N-1 N N-1 DMA MTN RBD Value of customer reliability Location specific Value of Customer Reliability (VCR) is used to calculate expected unserved energy. Where a limitation impacts multiple zone substations, an average VCR of the affected zone substations is used to calculate customer value of lost load. The location VCR was derived from the sector VCR estimates provided by AEMO, weighted in accordance with the composition of the load, by sector, at the relevant zone substations. Table 15 Summary of location specific VCRs Zone substation VCR ($ per MWh) DMA 54,130 MTN 65,220 RBD 68,280 Page 27 of 53

29 6 Summary of submissions On 28 March 2014, UE published the Non Network Options Report (NNOR) providing details on the network limitations within the Dromana supply area. This report sought information from Registered Participants and Interested Parties regarding alternative potential credible options or variants to the potential credible network options presented by UE. In response to the report, UE received enquiries from several non-network service providers. UE engaged in joint planning with these proponents to assess the viability of credible alternative solutions within the Dromana supply area. UE received two submissions by 20 June 2014, being the closing date for submissions to the NNOR. The first submission from GreenSync Pty Ltd indicated that they had undertaken detailed assessment of the Dromana area, which included technical analysis of the data supplied in the NNOR and a comprehensive customer survey of the Dromana area. GreenSync identified only a small amount of curtailable load which is insufficient to address the identified need or defer proposed network investment. GreenSync therefore concluded that there are no potential credible non-network solutions within the Dromana supply area. GreenSync s submission is available on UE s website. 18 The second submission received via from Cogent Energy also indicated that there are no identified credible non-network solutions within the Dromana supply area. 18 UE: Submissions on Non Network Options Report. Available at: Page 28 of 53

30 7 Credible options included in this RIT-D UE presented seven network options in the Non Network Options Report published on 28 March Five of these options were regarded as not being credible for the reasons set out in that report. 19 Given there are no credible non-network solutions, only two credible options have been considered for further detailed assessment and application of the RIT-D. Details of the credible network options are presented in the table below. Table 16 Credible options under consideration Option Option 1 Option 2 This option includes: This option will: Description Installing a new 20/33 MVA 66/22 kv transformer at Dromana zone substation. Extending the 22 kv busbar at Dromana zone substation. Developing two new 22 kv distribution feeders to supply the existing loads in and around Dromana area. Prevent the risk of supply interruption under system normal conditions. Prevent the risk of supply interruption following the loss of the Dromana zone substation transformer. Reduce utilisation of the distribution feeders in the Dromana area. Improve reliability performance of the distribution feeders in the Dromana area. The estimated capital cost of this option is $7.6 million (± 10%), in $AUD. Annual operating and maintenance costs are anticipated to be around 1% of the capital cost. The estimated commissioning date is December This option includes: This option will: Installing a new 20/33 MVA 66/22 kv transformer at Mornington zone substation. Developing three new 22 kv distribution feeders at Mornington zone substation to supply the existing loads in and around Dromana area. Developing one new 22 kv distribution feeder at Rosebud zone substation to supply the existing loads in and around Dromana area. Prevent the risk of supply interruption under system normal conditions. Partially reduce the risk of supply interruption following the loss of the Dromana zone substation transformer. Reduce utilisation of the distribution feeders in the Dromana area. Improve reliability performance of the distribution feeders in the Dromana area. The estimated capital cost of this option is $15.6 million (± 10%), in $AUD. Annual operating and maintenance costs are anticipated to be around 1% of the capital cost. The estimated commissioning date is December UE: Non Network Options Report. Available at: Page 29 of 53

31 8 Market modelling methodology The RIT-D requires market benefits to be calculated by comparing the state of the world in the base case (where no action is undertaken by UE) with the state of the world with each of the credible options in place. The state of the world means a reasonable and mutually consistent description of all of the relevant supply and demand characteristics and conditions that may affect the calculation of the market benefits over the period of assessment. 20 The uncertainty associated with the future state of the world is addressed by considering a number of reasonable scenarios (Refer to Section 9.3). In order to calculate the outcomes in the relevant state of the world, UE has developed the risk assessment model which incorporates the key variables that drive market benefits, as discussed in Section 5. The RIT-D assessment has been undertaken over a twenty-year period. The modelling discussed in Section to Section below has been undertaken across a ten-year study horizon. The market benefits calculated in the final year of the modelling period (i.e ) has been applied as the assumed annual market benefit that would continue to arise for a further ten years. This approach of adopting an extended analysis period, based on continuation of an assumed end value is one which has been adopted in similar assessments. 21 UE believes that this approach is a reasonable approach, given the long-lived nature of the investments considered in this RIT-D assessment. 8.1 Classes of market benefits considered The purpose of the RIT-D is to identify the credible option that maximise the present value of net market benefits to all those who produce, consume and transport electricity in the National Electricity Market (NEM). 22 In order to measure the increase in net market benefit, UE has analysed the classes of market benefits required to be considered by the RIT-D. 23 The market benefits considered not to be material have been identified in Section 8.2 of this DPAR. The classes of market benefits that are considered material and have been quantified in this RIT-D assessment are: Changes in involuntary load shedding; Changes in load transfer capability; and Changes in network losses. 20 AER: Regulatory Investment Test for Distribution Application Guidelines August 2013, Section Available 21 AEMO: Regional Victorian Thermal Upgrade RIT-T Project Assessment Draft Report, March Available: Capacity-Upgrade Powerlink and TransGrid: Development of the Queensland NSW interconnector, March Available: 22 AER: Regulatory Investment Test for Distribution Application Guidelines August 2013, Section 1.1. Available 23 NER: clause (c) paragraph 4. Page 30 of 53

32 8.1.1 Changes in involuntary load shedding Increasing the supply capability within the Dromana supply area increases the supply available to meet the maximum demand within the Dromana area. This will provide a greater reliability for this region by reducing potential supply interruptions and the consequent risk of involuntary load shedding. UE has used the risk assessment model to calculate the impact of changes in involuntary load shedding by comparing the expected unserved energy under the base case (where no action is undertaken by UE) with each of the credible option in place. Specifically, the model estimates the customer value of lost load by estimating the magnitude of unserved energy in each hour over the modelling period (expressed in MWh), after considering the impact of load transfers, and applying the locational VCR (expressed in $/MWh). An increase in the customer value of lost load (compared to the base case) makes a negative contribution to the market benefit of a credible option while a reduction in the customer value of lost load (compared to the base case) makes a positive contribution to the market benefit of a credible option. The customer value of lost load was calculated by: 1. Identifying the expected unserved energy due to insufficient capacity at DMA zone substation and multiplying by the locational VCR. 2. Identifying the expected unserved energy due to limitations in the distribution feeders within the Dromana supply area and multiplying by the locational VCR. The expected unserved energy due to insufficient capacity at DMA zone substation has been quantified as follows: 1. Identify the expected unserved energy at DMA zone substation under system normal conditions (i.e. N condition) and following the loss of the DMA zone substation transformer (i.e. N-1 condition) by considering load transfer capability. 2. Identify the incremental expected unserved energy at MTN zone substation due to transferring load away from DMA to MTN, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy at MTN zone substation before load transfer with the expected unserved energy at MTN zone substation after load transfer. 3. Identify the incremental expected unserved energy on the MTN distribution feeder network due to transferring load away from DMA to MTN, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy on the MTN distribution feeder network before load transfer with the expected unserved energy on the MTN distribution feeder network after load transfer. 4. Identify the incremental expected unserved energy at RBD zone substation due to transferring load away from DMA to RBD, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy at RBD zone substation before load transfer with the expected unserved energy at RBD zone substation after load transfer. Page 31 of 53

33 5. Identify the incremental expected unserved energy on the RBD distribution feeder network due to transferring load away from DMA to RBD, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy on the RBD distribution feeder network before load transfer with the expected unserved energy on the RBD distribution feeder network after load transfer. The combined expected unserved energy from (1) to (5) represents the expected unserved energy due to insufficient capacity at DMA zone substation. The expected unserved energy due to distribution feeder limitations was calculated as follows: 1. Identify the expected unserved energy in the distribution feeder network under status-quo for each credible option. 2. Identify the expected unserved energy in the distribution feeder network following the implementation of each credible option (i.e. residual risks) Changes in load transfer capability Following a major outage of the transformer at DMA zone substation, customers supply can be restored (in part) via the distribution network from neighbouring zone substations at MTN and RBD. Where there is adequate load transfer capability, the numbers of customers exposed to the risk of supply interruption can be significantly reduced. Although this reduces the expected unserved energy at DMA (compared to the level of expected unserved energy in the absence of any load transfers to neighbouring network), it may increase the level of expected unserved energy at MTN and RBD. The modelling undertaken in Section considers any changes in load transfer that may be expected to occur with each of the credible options in place. A reduction in load transfer from DMA to neighbouring network (compared to the base case) results in reduced expected unserved energy (net), which makes a positive contribution to market benefit of a credible option Changes in network losses Increasing the supply capability within the Dromana area can lead to a reduction in network losses compared with the level of network losses which would occur in the base case. The market benefits associated with the change in network losses have been quantified by a direct calculation of the likely MWh impact on the losses for each year of the modelling horizon. Specifically, losses on the distribution feeders and zone substations have been estimated by multiplying the network losses at the time of maximum demand by the loss load factors for These MWh figures for losses have then been multiplied by the value of those losses, as measured by the average Victorian spot price for , in accordance with the methodology prescribed in the RIT-D Applications Guidelines The load loss factors of distribution feeders were estimated by considering the network topology following the implementation of each credible option. This was achieved by considering backbone length of the reconfigured feeder, geometry of the reconfigured feeder (i.e. location of the load, backbone conductor UG vs. Cable etc.) 25 AER: Regulatory Investment Test for Distribution Application Guidelines, Example 22. Available Page 32 of 53