Lower Mornington Peninsula Supply Area

Transcription

1 Non Network Options Report RIT-D Report This report presents the sub-transmission network limitations in the lower Mornington Peninsula including options and technical characteristics of non-network options to alleviate those limitations.

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3 Table of Contents 1 Approval and Document Control 3 2 Executive summary 4 3 Introduction 5 4 Identified Need Network overview Description of the identified need Voltage collapse limitation Insufficient thermal capacity in sub-transmission network Bushfire exposure Closing comments on the need for investment Quantification of the identified need 14 5 Key assumptions in relation to the Identified Need Method for quantifying the identified need Expected unserved energy due to voltage collapse limitation Expected unserved energy due to insufficient thermal capacity Forecast maximum demand Characteristic of load profile Plant failure rates Sub-transmission network losses under N-1 condition Plant ratings Value of customer reliability Discount rates 23 6 Potential credible options to address the identified need 24 7 Technical characteristics of non-network options Size and location Time of year Reliability Operation 29 8 Submission Request for submission Next steps 30 9 Abbreviations and Glossary 31 Page 2 of 33

4 1 Approval and Document Control VERSION DATE AUTHOR 1 18 December 2014 UE Network Planning Amendment overview New document Page 3 of 33

5 2 Executive summary The lower Mornington Peninsula is supplied by a 66kV sub-transmission network supplying Dromana (DMA), Rosebud (RBD) and Sorrento (STO) 66/22 kv zone substations. These three zone substations together with other zone substations in the region including Frankston South (FSH), Hastings (HGS) and Mornington (MTN) are supplied from the 220/66 kv transmission connection point known as Tyabb Terminal Station (TBTS), the sole source of electricity supply to the Mornington Peninsula from the Victorian shared transmission network. The 66 kv sub-transmission network which supplies this region is relatively long with the transmission connection point located on the eastern side of the Mornington Peninsula and most of the load centres located on the west side. This sub-transmission network is also highly utilised at maximum demand. On the present forecast, it is estimated that the following sub-transmission lines, which provide electricity supply to the region, will have maximum demands that exceed their N-1 thermal ratings: DMA-RBD No. 1 66kV line; DMA-RBD No kv line; MTN-DMA 66 kv line; TBTS-DMA 66 kv line; and TBTS-MTN No.1 66 kv line. The other more pressing issue is the inability of the network to maintain voltage levels within regulatory limits in the event of an outage of either the MTN-DMA 66 kv line or the TBTS-DMA 66 kv line at maximum demand conditions, with the former being the more severe condition. Given the relatively long distance of existing zone substations and the load centres from the transmission connection point in this region, all credible network options are relatively expensive to implement. United Energy (UE) has identified two potential credible network options that are technically comparable to address the identified need: 1. Install a new HGS-RBD 66 kv line for service by December The estimated capital cost of this option is $25.3 million (±30%). 2. Install a new TBTS-RBD 66 kv line for service by December The estimated capital cost of this option is $26.9 million (±30%). Alternatively, demand reduction or embedded generation up to 30 MVA in summer would be required to address both the thermal and voltage limitations. UE has already received a proposal from one non-network service provider to reduce demand in the lower Mornington Peninsula. Details of this proposal are currently being confirmed. UE welcomes written submissions from other registered participants and interested parties to address the issues described in this consultation report on or before 29 May All Submissions and enquiries should be directed to the United Energy Manager Network Planning at planning@ue.com.au. Page 4 of 33

6 3 Introduction This Non Network Options Report has been prepared by United Energy (UE) in accordance with the requirements of clause (e) of the National Electricity Rules (NER). This report represents the first stage of the consultation process in relation to the application of the Regulatory Investment Test for Distribution (RIT-D) on potential credible options to address the sub-transmission network limitations in the lower Mornington Peninsula. The need for investment and the possible options for addressing limitations have been foreshadowed in UE s 2013 Distribution Annual Planning Report (DAPR). 1 This report: Provides background information on the sub-transmission network limitations in the lower Mornington Peninsula. Identifies the need which UE is seeking to address, together with the assumption used in identifying that need. Describes the credible options that UE currently considers may address the identified need, including for each: o o o Its technical definitions; The estimated commissioning date; and The total indicative cost (including capital and operating costs). Sets out the technical characteristics that a non-network option would be required to deliver in order to address the identified need. An invitation to registered participants and interested parties to make submission on credible options to address the identified need. 1 UE: Distribution Annual Planning Report. Available at: Page 5 of 33

7 4 Identified Need 4.1 Network overview The geographic area that comprises the lower Mornington Peninsula include Cape Schanck, Dromana, Flinders, Main Ridge, McCrae, Portsea, Red Hill, Rosebud, Rye, Shoreham and Sorrento. The electricity demand in this region is made up of predominantly residential sector demand with the majority of the population load centres based along the coastline of Port Phillip Bay. Pockets of commercial and light industrial sectors are also based in the major population centres. The lower (south-western) Mornington Peninsula is currently supplied by Dromana (DMA), Rosebud (RBD) and Sorrento (STO) 66/22kV zone substations as illustrated in Figure 1. Figure 1 Geographical regions of the lower Mornington Peninsula STO RBD DMA Recent trends have shown a large growth in electricity demand in the residential sector on the Mornington Peninsula. The number of permanent residents is increasing as holiday homes are being converted into permanent dwellings, residential developments and retirement villages. 2 The Mornington Peninsula remains one of Melbourne s premier holiday destinations. The population being serviced rises from approximately 150,000 in early December to a peak of nearly 195,000 during the summer months. 3 2 The Mornington Peninsula is predicted to have the strongest population growth in the UE service area over the next 10 years. The predicted annual average population growth in the Mornington Peninsula is about 1.6% over the 2015 to 2025 period compared to an average of 1.1% for the total UE service area. 3 Mornington Peninsula Shire: Shire Strategic Plan Available at: Page 6 of 33

8 Figure 2 below illustrates the existing sub-transmission network arrangements in the lower Mornington Peninsula. Figure 2 Existing sub-transmission configuration in the Mornington Peninsula (schematic view) TBTS-MTN No.1 66kV Line MTN-DMA 66kV Line DMA-RBD No. 1 & No. 2 66kV Lines TBTS-DMA 66kV Line The existing sub-transmission network to DMA, RBD and STO zone substations consist of: One 66 kv line from Tyabb Terminal Station (TBTS) to DMA zone substation; One 66 kv line from Mornington (MTN) zone substation to DMA zone substation; Two 66 kv lines from DMA to RBD zone substation; and Two 66 kv radial lines from RBD to STO zone substations. This network is currently supporting more than 120 MVA of electrical load at times of maximum demand. The lengths of the 66 kv line segments from TBTS to DMA, to RBD and finally to STO are 29 km, 12 km and 18 km respectively, indicating that the supply route extends for 59 km. Given the relatively long length of the sub-transmission network and high demand, capacitor banks are installed at STO and RBD zone substations to provide reactive power compensation for the load, with one bank at STO used to slightly over-compensate the power factor to minimise reactive power losses in the 66 kv lines. Both these stations are currently operating near unity power factor. Although DMA zone substation is not equipped with any capacitor banks, the zone substation also operates near unity power factor due to the use of pole-mounted capacitor banks within the 22 kv distribution network. The effectiveness of these devices together with the on-load Page 7 of 33

9 tap changers (of zone substation transformers) to maintain voltage levels within acceptable levels is diminishing rapidly in the event of loss of one of the sub-transmission lines to DMA zone substation during maximum demand conditions because of the magnitude of the losses along the 66 kv lines, particularly for loss of the MTN-DMA 66kV line. The distribution network in the lower Mornington Peninsula is characterised by relatively long distribution feeders with below average reliability performance compared to the overall UE network. As a result, the transfer capability in this region is limited during summer maximum demand conditions. The extent of the distribution network in this region is illustrated in Figure 3. Figure 3 Existing distribution network in the Mornington Peninsula FSH MTN HGS DMA STO RBD Page 8 of 33

10 4.2 Description of the identified need Voltage collapse limitation The lower Mornington Peninsula is currently supplied by DMA, RBD and STO zone substations. An unplanned outage either of the incoming 66 kv sub-transmission lines to DMA (i.e. MTN-DMA or TBTS-DMA) during summer maximum demand conditions could cause voltage in the lower Mornington Peninsula to drop uncontrollably, leading to voltage collapse and ultimately supply interruption to the entire region. In order to avoid voltage collapse, pre-emptive load reductions would be required during summer maximum demand periods. The figure below depicts the historical actual maximum demand in the lower Mornington Peninsula, 10% 4 and 50% 5 PoE summer maximum demand forecasts together with the voltage collapse limits. Figure 4 Forecast maximum demand against voltage limits for lower Mornington Peninsula 6 As illustrated above: An unplanned outage of the MTN-DMA 66 kv line at 10% and 50% PoE summer maximum demand conditions is expected to lead to voltage collapse in the lower Mornington Peninsula from summer Therefore, pre-contingent load curtailment may be required from this time to maintain regulatory compliance with respect to voltage. 4 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. 5 This forecast is also referred to as having a 50% probability of exceedance. It represents a forecast that is expected, on average, to be exceeded once in two years. 6 The voltage limits under each credible contingency were calculated using a series of PSS/E (power system simulation software) simulations by considering various loading scenarios. Page 9 of 33

11 An unplanned outage of the TBTS-DMA 66 kv line at 10% PoE summer maximum demand conditions is expected to lead to voltage collapse in the lower Mornington Peninsula from summer Therefore, pre-contingent load curtailment may be required from this time to maintain regulatory compliance with respect to voltage. The table below summarises the forecast impact of the voltage collapse limitation, in particular: Load at risk, which is the MVA load shedding required to address the voltage collapse limitation at 10% PoE maximum demand forecast. This represents the pre-emptive load reduction. Hours at risk, which is the duration of load shedding required to address the voltage collapse limitation. Expected unserved energy at risk 7, which is portion of the energy at risk after taking into account the probability of the demand conditions occurring. Expected value of unserved energy is obtained by multiplying the expected unserved energy by the Value of Customer Reliability (VCR). Table 1 Forecast voltage limitation Year Load at Risk 8 adadffadfda (MVA) Hours at Risk afdafdadfad (Hours) Expected Energy at Risk (kwh) Expected value of unserved energy ($,000) , , , ,903 1, ,537 2, ,189 3, ,337 5, ,974 7, ,160 11, ,186 15,663 7 The expected unserved energy is the portion of the energy at risk taking into account the probability of an outage, combined with a 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand, as described in Section The maximum load reduction required to address the voltage limitation (assumes no diversity between the three zone stations). Page 10 of 33

12 4.2.2 Insufficient thermal capacity in sub-transmission network On the present forecast, it is estimated that the following sub-transmission lines 9, which provide electricity supply to the lower Mornington Peninsula, will have maximum demands that exceed their N-1 thermal ratings: DMA-RBD No.1 66 kv line for loss of the DMA-RBD No.2 66 kv line. DMA-RBD No.2 66 kv line for loss of the DMA-RBD No.1 66 kv line. MTN-DMA 66 kv line for loss of the TBTS-DMA 66 kv line. TBTS-DMA 66 kv line for loss of the MTN-DMA 66 kv line. TBTS-MTN No.1 66 kv line for loss of TBTS-DMA 66 kv line. 10 Unlike other parts of the UE network where load can be transferred to adjacent sub-transmission systems, the load transfer capability away from abovementioned network is significantly limited. This is because: For the DMA-RBD lines which supply RBD and STO zone substations, only RBD has offloading capability to neighbouring DMA zone substation. For the TBTS-DMA and MTN-DMA lines which supply DMA, RBD and STO zone substations, only DMA has off-loading capability to neighbouring MTN zone substation. For the TBTS-MTN No.1 line which supplies the DMA, FSH, MTN, RBD and STO zone substations, a limited amount of load can be transferred from MTN to neighbouring FSH and HGS zone substations. It has a highly utilised distribution feeder network with below average reliability performance. The table below summarises the forecast impact of thermal limitations, in particular: Load at risk, which is the MVA load shedding required to address the abovementioned thermal limitations at 10% PoE maximum demand forecast (i.e. the worst case scenario). This represents a post-contingent load reduction after considering the impact of load transfer capability. Hours at risk, which is the duration of load shedding required addressing the abovementioned thermal limitations. Expected unserved energy at risk 11, which is portion of the energy at risk after taking into account the probability of the demand conditions occurring and plant unavailability. 9 Only the outages that lead to overload and results in the highest loading levels of the remaining sub-transmission network is listed. 10 The TBTS-MTN No.1 66 kv line also becomes overloaded following the loss of the TBTS-MTN No.2 66 kv line. 11 The expected unserved energy is the portion of the energy at risk taking into account the probability of an outage, combined with a 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand, as described in Section 5.3. Page 11 of 33

13 Expected value of unserved energy is obtained by multiplying the expected unserved energy by the Value of Customer Reliability (VCR). Table 2 Forecast thermal limitations Year Load at Risk adadffadfda (MVA) Hours at Risk afdafdadfad (Hours) Expected Energy at Risk (kwh) Expected value of unserved energy ($,000) , , , , , , Page 12 of 33

14 4.3 Bushfire exposure Large areas of natural bush, state parks or local reserves, rural fields and other vegetation co-exist along populated areas of the Mornington Peninsula. Therefore, there exists a higher threat of bushfire in many parts of this region compared to other parts of UE s service area. In recent years, UE has observed four separate incidents of sub-transmission line forced outages as a result of bushfire-related incidents in the area. Two of these incidents related to outage of both the DMA-RBD 66 kv lines (i.e. N-2 outage). This resulted in total loss of supply to a majority of the lower Mornington Peninsula (i.e. all of RBD and STO zone substations). The prospect of bushfire-related factors leading to outage of both the DMA-RBD 66 kv lines is greater in the area of Arthurs Seat Park where both lines traverse in close proximity in difficult to access terrain with thick vegetation. In light of recent events, UE considers the loss of both the DMA-RBD 66 kv lines, due to bushfirerelated incidents, to be a credible contingency event. UE has not quantified this risk as part of this report. Instead, UE discusses qualitatively whether each potential credible option discussed in Section 6 addresses the risk of loss-of-supply under an N-2 contingent event. 4.4 Closing comments on the need for investment The following limitations are to be addressed by this RIT-D: From summer , an unplanned outage of one of the incoming sub-transmission lines to DMA zone substation during summer maximum demand conditions is expected to lead to voltage collapse in the lower Mornington Peninsula. From summer , an unplanned outage of a critical sub-transmission line during summer maximum demand conditions is expected to lead to supply interruptions in the lower Mornington Peninsula due to thermal overload of remaining in-service subtransmission lines. Outage of both the DMA-RBD 66 kv lines due to bushfire incidents are expected to lead to total loss of supply to a majority of the lower Mornington Peninsula until one or both lines are fully restored. In light of the growing demand and the forecast increase in load-at-risk, UE has examined a number of options to alleviate the identified need. These options are outlined in Section 6. Page 13 of 33

15 4.5 Quantification of the identified need The table below summarises the forecast impact of the identified need discussed in Section 4.2. The table shows: Load at risk, which is the MVA load shedding required to address the sub-transmission network limitations at 10% PoE maximum demand forecast. This represents both the precontingent load reductions and post-contingent load reductions. Hours at risk, which is the duration of load shedding required to address the subtransmission limitations. Expected unserved energy at risk 12, which is portion of the energy at risk after taking into account the probability of the limitation occurring, including the probability of the demand conditions occurring. Expected value of unserved energy is obtained by multiplying the expected unserved energy by the Value of Customer Reliability (VCR). Table 3 Forecast sub-transmission network limitations in the lower Mornington Peninsula Voltage Limitation (Pre-contingent) Thermal Limitation (Post-contingent) Total Limitation Year Load at Risk fffffffff Hours at Risk Load at Risk fffffffff Hours at Risk Expected Energy at Risk Expected value of unserved energy (MVA) (Hours) (MVA) (Hours) (kwh) ($,000) , , , ,812 1, ,665 3, ,615 4, ,968 5, ,057 7, ,519 11, ,120 15, The expected unserved energy is the portion of the energy at risk taking into account the probability of an outage, combined with a 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand, as described in Section 5.3. Page 14 of 33

16 5 Key assumptions in relation to the Identified Need 5.1 Method for quantifying the identified need The identified need that is to be addressed by this RIT-D, presented in Section 4.5, is comprised of the following components: Expected unserved energy due to voltage collapse limitation in the lower Mornington Peninsula; and Expected unserved energy due to insufficient thermal capacity in the sub-transmission network. The section below summarises the method adopted to quantify the abovementioned risks Expected unserved energy due to voltage collapse limitation In order to avoid the voltage collapse limitation and maintain voltage stability, load must be reduced during system normal conditions (i.e. prior to an outage) at times when the total load in the lower Mornington Peninsula reaches the voltage collapse limit to maintain regulatory compliance. The expected unserved energy due to voltage collapse limitation was estimated as follows: Identify the expected unserved energy under system normal conditions by comparing the total demand in the lower Mornington Peninsula (i.e. combined demand at DMA, RBD and STO zone substations) against the voltage collapse limit Expected unserved energy due to insufficient thermal capacity The expected unserved energy due to insufficient thermal capacity in the sub-transmission network was calculated as follows: 1. Identify the expected unserved energy in the following sub-transmission network under system normal conditions (i.e. N condition) and following loss of a critical sub-transmission line (i.e. N-1 condition): a. DMA-RBD lines which supplies RBD and STO zone substations. b. TBTS-DMA line which supplies DMA, RBD and STO zone substations. c. MTN-DMA line which supplies DMA, RBD and STO zone substations. d. TBTS-MTN No.1 line which supplies DMA, FSH, MTN, RBD and STO zone substations. The combined expected unserved energy from (a) to (d) represents the expected unserved energy that is to be addressed due insufficient thermal capacity in the sub-transmission network. This assessment excludes the impact of load transfer capability. Analysis indicated that the total risks to be addressed due to insufficient thermal capacity in the sub-transmission network is greater under the scenario that considers the impact of load transfers compared to the scenario Page 15 of 33

17 Maximum demand (MVA) RIT-D Non Network Options Report that excludes such transfers. 13 This is due to significant incremental risks in the distribution feeder network, particularly during N-1 conditions where the distribution feeders are exposed to greater level of risk given increased utilisation. In order to realise market benefits arising from load transfers to neighbouring network during emergency conditions, the available load transfer capability must be optimised such that the incremental risks in the distribution feeder network is reduced (particularly under N-1 conditions). This requires significant iterative modelling assessment which would be disproportionate to any additional benefits that may be identified given: High proportion of the identified need relates to the voltage collapse limitation. Any additional benefits realised from load transfers during emergency conditions would not alter the timing of proposed augmentation nor alter the outcome of this RIT-D. The available load transfer is already limited and expected to deteriorate. Further reduction is unlikely to yield significant market benefits. 5.2 Forecast maximum demand Forecasts of the 10% PoE and 50% PoE summer maximum demand for the relevant zone substations and sub-transmission systems in the lower Mornington Peninsula are presented in figures below. These forecasts are based on the base (expected) economic growth scenario. Figure 5 10% PoE summer maximum demand forecasts at DMA, RBD and STO zone substations Forecast 10% PoE summer maximum demand DMA RBD STO 13 Load transfer capability away from sub-transmission systems on the UE network was calculated for summer as part of contingency planning studies. Page 16 of 33

18 Maximum demand (MVA) Maximum demand (Amps) RIT-D Non Network Options Report Figure 6 10% PoE summer maximum demand forecasts of relevant sub-transmission systems Forecast 10% PoE summer maximum demand TBTS-DMA-FSH-MTN-TBTS TBTS-DMA-MTN DMA-RBD-DMA Figure 7 50% PoE summer maximum demand forecasts at DMA, RBD and STO zone substations Forecast 50% PoE summer maximum demand DMA RBD STO Page 17 of 33

19 Maximum demand (Amps) RIT-D Non Network Options Report Figure 8 50% PoE summer maximum demand forecasts of relevant sub-transmission systems Forecast 50% PoE summer maximum demand TBTS-DMA-FSH-MTN-TBTS TBTS-DMA-MTN DMA-RBD-DMA The amount of expected unserved energy is estimated in this report by taking 30% weighting of the unserved energy at 10% PoE demand forecast and 70% weighting of the unserved energy at 50% PoE demand forecast. Page 18 of 33

20 Normalised Load (%) RIT-D Non Network Options Report 5.3 Characteristic of load profile The Mornington Peninsula remains one of Melbourne s premier seasonal holiday destinations. As such, the maximum demand occurs during summer holiday periods as illustrated in Figure 9. Figure 9 Load profile for lower Mornington Peninsula ( ) Lower Mornington Peninsula Load Profile 110% 100% Winter Spring Summer Autumn 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Hours A typical load profile on the day of summer maximum demand is presented in Figure 10. Normally, the electricity demand in the lower Mornington Peninsula remains relatively low during the early hours of the day, with a large increase in demand during the afternoon to early evening hours. Page 19 of 33

21 Proporation of maximum demand 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 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 (%) RIT-D Non Network Options Report Figure 10 Typical load profile on day of summer maximum demand for lower Mornington Peninsula Lower Mornington Peninsula Daily peak load profile 110% 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Time of day Figure 11 shows the normalised load duration curves of the lower Mornington Peninsula for the last five summers. Figure 11 Historical load duration curves for lower Mornington Peninsula Load duration curve for lower Mornington Peninsula 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 20 of 33

22 The figure above shows that that the load characteristics can vary from year to year. It also shows that around 45-60% of the maximum demand lasts less than five 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% and 50% PoE demand profiles (or close to) for the lower Mornington Peninsula 14 ; Maximum demand occurring during summer holiday periods; and Excludes load transfer from / to neighbouring network. Based on this approach, the expected unserved energy due to both thermal and voltage limitations were estimated using the and historical traces. 5.4 Plant failure rates The base (average) outage data adopted in this RIT-D are presented below. Table 4 Summary of sub-transmission line outage rates Major plant item: Sub-transmission lines Interpretation Sub-transmission line failure rate per km Duration of outage (major fault) 5.1 faults per 100 km per annum 10 hours The average sustained failure rate of UE s subtransmission network is 5.1 faults per 100 km per year. A total of 10 hours is required to repair / replace the sub-transmission line (or sections of the line), during which time the sub-transmission line (or sections of the line) is not available. 5.5 Sub-transmission network losses under N-1 condition As discussed earlier, the lower Mornington Peninsula is supplied by an extended sub-transmission network. The network losses following the loss of a critical sub-transmission line in the region is significant, particularly in the case where the total supply is via the radial TBTS-DMA-RBD-STO sub-transmission network. To account for the network losses under N-1 conditions, UE has adopted 3.0 per-cent of the total load in this assessment. 14 The total demand in the lower Mornington Peninsula was estimated by summing the individual station demands at DMA, RBD and STO zone substations. This method considers diversity exhibited in the historical base trace. 15 The historic load traces characterised (or close to) a 10% PoE maximum demand profile in the lower Mornington Peninsula. 16 The historic load trace characterised (or close to) a 50% PoE maximum demand profile in the lower Mornington Peninsula. Page 21 of 33

23 5.6 Plant ratings The voltage collapse ratings under each credible sub-transmission line outage were calculated using a series of PSSE simulations by considering various loading scenarios. The critical voltage collapse rating is for the loss of the MTN-DMA 66 kv line, where the total supply to the lower Mornington Peninsula is from the radial TBTS-DMA-RBD-STO sub-transmission network. The sub-transmission line thermal ratings were 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 ratings adopted in this assessment are summarised in the table below. Table 5 Summary of sub-transmission line cyclic ratings (MVA) Description Summer cyclic rating at 40 C N N-1 Voltage rating N/A Thermal rating: DMA-RBD 66 kv lines Thermal rating: TBTS-DMA 66 kv line Thermal rating: MTN-DMA 66 kv line Thermal rating: TBTS-FSH-MTN-DMA-TBTS system Value of customer reliability Location specific Value of Customer Reliability (VCR) is used to calculate the customer value of lost load. Where a limitation impacts multiple zone substations, an average VCR of the affected zone substations is used to calculate the 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. 17 The voltage rating following the loss of the MTN-DMA 66 kv line. 18 The thermal rating following the loss of one of the DMA-RBD 66 kv lines. 19 The thermal rating following loss of the MTN-DMA 66 kv line. 20 The thermal rating following loss of the TBTS-DMA 66 kv line. 21 The thermal rating following loss of the TBTS-DMA 66 kv line. Page 22 of 33

24 Table 6 Summary of location specific VCRs (based on 2013 estimates) Zone substation VCR ($ per MWh) DMA 54,130 FSH 57,255 MTN 65,221 RBD 68,280 STO 54,140 While AEMO s recent VCR review in 2014 concludes a reduction in its baseline VCR, the timebased VCRs in Appendix B of AEMO s Final Report conclude that the revised VCRs are comparable in magnitude to those presented above. Given the AEMO consultation on the VCR Application Guidelines is still in progress at the time of developing this report, the VCRs above may be updated for the Draft Project Assessment Report (DPAR). 5.8 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 RIT-D. Page 23 of 33

25 6 Potential credible options to address the identified need The table below provides a summary of potential credible options to address the identified need. Table 7 Credible options under consideration Option Description 1 Install a new HGS-RBD 66 kv line This option includes: This option will: Installing approximately 53 km of new 66 kv line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation. The new line would be constructed along the south-eastern coast (along the road reserve) of the Mornington Peninsula, clear of high bushfire zones. Most of the route would involve the reconstruction of existing overhead pole lines. Installing three 66 kv circuit breakers, one at RBD and two at HGS zone substations. Upgrade the TBTS-HGS No.1 and No.2 feeder exits at Tyabb Terminal Station (TBTS). Addresses the thermal limitations by reducing utilisation of the constrained sub-transmission network. Addresses the voltage limitation by improving voltage regulation in the lower Mornington Peninsula. Addresses the risk of bushfire-related incidents leading to outage of both the DMA-RBD 66 kv lines. Facilitates the sub-transmission connection of a future zone substation in the Flinders / Shoreham area. Based on the current forecasts, this new zone substation is not required within the next 20 year planning period. The estimated capital cost of this option is $25.3 million (± 30%), in $AUD. Annual operating and maintenance costs are anticipated to be around 0.5% of the capital cost. 22 The above-estimate includes the cost of the TBTS-HGS No.1 and No.2 feeder exit upgrade works which would be undertaken by AusNet Transmission Group. The estimated commissioning date is before summer The estimated total annual cost of this option is $2,403,500. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to avoid this augmentation. 2 Install new TBTS-RBD 66 kv line This option includes: Installing 3.4 km of additional 66 kv line from TBTS to HGS zone substation. Installing approximately 53 km of new 66 kv line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation. The new line would be constructed along the south-eastern coast of the Mornington Peninsula, clear of high bushfire zones. Most of the route would involve the reconstruction of existing overhead pole lines. Installing two 66 kv circuit breakers, one at RBD and one at TBTS (Bus 3). This option: Addresses the thermal limitations by reducing utilisation of the constrained sub-transmission network. 22 Based on the average maintenance cost of overhead lines per km for Page 24 of 33

26 Option Description 2 Addresses the voltage limitation by improving voltage regulation in the lower Mornington Peninsula. Addresses the risk of bushfire related incidents leading to outage of both the DMA-RBD 66 kv lines. Facilitates the sub-transmission connection of a future zone substation in the Flinders / Shoreham area. Based on the current forecasts, this new zone substation is not required within the next 20 year planning period. The estimated capital cost of this option is $26.9 million (± 30%), in $AUD. Annual operating and maintenance costs are anticipated to be around 0.5% of the capital cost 21. The estimated commissioning date is before summer The estimated total annual cost of this option is $2,555,500. This cost provides a broad upper bound indication of the maximum contribution from UE which may be available to non-network service providers to avoid this augmentation. 3 Non-network solutions Embedded generation or demand reduction may defer network investments to address the identified need. UE has been working with a number of non-network service providers under the Memorandum of Understanding (MoU). At the time of publication of this report, UE has received a proposal from one proponent providing an option for demand reduction within the lower regions of the Mornington Peninsula. Likely costs and operating parameters are currently being confirmed. Once confirmed, UE intends to evaluate this proposal to determine whether it is an alternative or complementary measure to network augmentation. The outcome of this assessment will be published in the Draft Project Assessment Report (i.e. the second consultation paper in relation to this RIT-D). UE welcomes proposals, including cost estimates from other non-network service providers to address the issues described in Section 4. Section 7 provides information to assist non-network service providers in responding to this consultation report. The table below describes the options that have been considered by UE, and are currently regarded as being not credible for the reasons set out: Table 8 Options regarded as being not credible Option Description 4 Upgrading existing sub-transmission systems This option includes: Reconductoring approximately 18 km of the DMA-RBD 66 kv lines. Reconductoring approximately 7 km of the TBTS-MTN No.1 66 kv line. The estimated capital cost of this option is $8.3 million (± 30%), in $AUD. This option does not fully address the thermal limitation nor does it address the voltage collapse limitation in the lower Mornington Peninsula. Given a majority of the identified need is associated with the voltage collapse limitation, the expected net market benefits of this option is likely to be considerably lower than the credible options discussed earlier. Under the RIT-D, the preferred option is the credible option that maximise the network market benefits. For this reason, UE does not consider this option to be a credible option. Page 25 of 33

27 Option Description 5 Reactive power compensation Reactive power compensation by means of installing capacitor banks at various zone substations in the lower Mornington Peninsula is not a technically viable option. This is because all zone substations in the region are operating near unity power factor. Currently, STO has already been overcompensated to minimise the risk of the voltage collapse limitation. For this reason, UE does not consider this option to be a credible option. 6 Install new HGS-STO 66 kv line This option includes: This option: Installing approximately 53 km of new 66 kv line from Hastings (HGS) zone substation to Rosebud (RBD) zone substation. The new line would be constructed along the south-eastern coast of the Mornington Peninsula, clear of high bushfire zones. Installing new 66 kv line from RBD to STO zone substation. Upgrade the TBTS-HGS No.1 and No.2 feeder exits at Tyabb Terminal Station (TBTS). Addresses the thermal limitations by reducing utilisation of the constrained sub-transmission network. Addresses the voltage limitation by improving voltage regulation in the lower Mornington Peninsula. Addresses the risk of bushfire related incidents leading to outage of both the DMA-RBD 66 kv lines. Facilitates the sub-transmission connection of future zone substation in the Flinders / Shoreham area. Based on the current forecasts, this new zone substation is not required within the next 20 year planning period. The estimated capital cost of this option is $33.1 million (± 30%), in $AUD. The above-estimate includes the cost of the TBTS-HGS No.1 and No.2 feeder exit upgrade works which would be undertaken by AusNet Transmission Group. Under this option, the new sub-transmission line is extended to STO zone substation. This relieves loading on the existing RBD-STO-RBD system under system normal and N-1 conditions. However, additional market benefits would not be realised given there is no immediate thermal limitation on this system. Therefore, the net market benefit associated with this option would be lower than the credible network options described earlier due to its higher costs. Under the RIT-D, the preferred option maximises the net market benefits. Therefore, this option would not satisfy the RIT-D. For this reason, UE does not consider this option to be a credible option. Page 26 of 33

28 Option Description 7 Install new HGS-DMA 66 kv line with DMA-RBD 66 kv line reconductoring This option includes: This option: Installing approximately 22 km of new 66 kv line from Hastings (HGS) zone substation to Dromana (DMA) zone substation. Reconductor approximately 18 km of the existing DMA-RBD 66 kv lines. Convert the existing 66 kv outdoor switchyard to Gas Insulated Switchgear (GIS) due to space constraints at DMA zone substation. Upgrade the TBTS-HGS No.1 and No.2 feeder exits at Tyabb Terminal Station (TBTS). Addresses the thermal limitations by reducing utilisation of the constrained sub-transmission network. Addresses the voltage limitation by improving voltage regulation in the lower Mornington Peninsula. The estimated capital cost of this option is $26.2 million (± 30%), in $AUD. The above-estimate includes the cost of the TBTS-HGS No.1 and No.2 feeder exit upgrade works which would be undertaken by AusNet Transmission Group. Although this option is similar to Option 1 in terms of both costs and the expected market benefits, UE has identified a number of issues associated with this options: The feasibility of constructing a sub-transmission line along the Mornington Peninsula Freeway is yet to be established. However, approval is likely to be difficult given UE s recent previous experience in the Keysborough area. The project cost is likely to increase if a route along the freeway cannot be achieved. The feasibility of reconstructing the sub-transmission lines between DMA and RBD is yet to be established. Easement renegotiations are likely to be expensive given UE s experience with land-holders for the previous upgrade of the TBTS-DMA 66 kv lines in this area. The project cost is significantly dependant on easement renegotiation costs for this option. This option does not facilitate the sub-transmission connection of a future zone substation in the Flinders / Shoreham area. This option does not address the risk of bushfire related incidents leading to outage of both the DMA-RBD 66 kv lines. Significant disruption / outages during conversion of existing 66 kv outdoor switchgear to 66 kv GIS switchgear at DMA zone substation. This is likely to increase the cost of this project. Given these practical limitations, reduced market benefits and potential increased costs compared to the potential credible options discussed earlier, UE does not consider this option to be a credible option. Page 27 of 33

29 7 Technical characteristics of non-network options This section describes the technical characteristics of the identified need that a non-network option would be required to deliver. A credible non-network option must satisfy timing, operational and technical requirements stipulated below. 7.1 Size and location Non-network service providers would need to be able to reduce load (demand-side or generation solutions) in the lower Mornington Peninsula to avoid network limitations discussed in this paper. This could be achieved by: 1. Pre-contingent load reductions. This arrangement would involve measures to reduce the load at times when an outage of the MTN-DMA 66 kv line results in voltage collapse in the lower Mornington Peninsula. 2. Post contingent load reductions. This arrangement would involve measures to reduce the load should a critical outage occur and the sub-transmission network be overloaded. Such reductions would need to occur within a few minutes of the critical outage occurring. Table 9 outlines the maximum amount of load reduction, or additional generation required to address the network limitations discussed in this paper. Non-network solutions must be provided in the Sorrento, Rosebud and/or Dromana supply areas. Table 9 Peak Demand offsets required from non-network solutions to address the identified need Pre-contingent requirements Post-contingent requirements Year Load at Risk Hours at Risk Load at Risk Hours at Risk (MVA) (hours) (MVA) (hours) Page 28 of 33

30 7.2 Time of year Proposed non-network options, at a minimum, must be capable of reducing demand in the lower Mornington Peninsula during summer holiday periods (typically from December to January inclusive). 7.3 Reliability Proposed non-network options must be capable of reliably meeting electricity demand under a range of conditions. If the non-network option is a generator operating in parallel with UE s network, the generator must comply with the requirements set out in UE s Embedded Generation Network Access Standard (Document No. UE ST 2008) Operation The market benefits associated with the identified need relate to: Reducing the expected amount of unserved energy due to voltage collapse limitation; and Reducing the expected amount unserved energy due to insufficient thermal capacity in a number of sub-transmission systems under N-1 condition. The load curve in Figure 10 shows that the demand in the lower Mornington Peninsula remains high over the hours from 3:00 pm to 8:00 pm. Any pre-contingent non-network solution will therefore need to be capable of operating continuously over this period, until the demand declines. Any post-contingent non-network solution will need to be capable of operating continuously, during high demand periods where there is insufficient spare capacity in neighbouring distribution feeders, until the faulted asset is repaired or replaced, or the demand declines. A high proportion of the total risk to be addressed by this RIT-D is associated with the voltage limitation. Therefore, any non-network solutions that address this limitation would be associated with significant market benefits Page 29 of 33

31 8 Submission 8.1 Request for submission UE invites written submissions on this report from registered participants and interested parties. All submissions should completely and comprehensively address the technical characteristics of non-network options provided in Section 7 and include information listed in listed in Section 5 of UE s Demand Side Engagement Document (DSED). 24 All Submissions and enquiries should be directed to the United Energy Manager Network Planning at planning@ue.com.au. Submissions are due on or before 29 May All submissions will be published on UE website Next steps Following UE s consideration of the submissions, a detailed option assessment including the preferred option to address the identified need, and a summary of, and commentary on, the submissions to this report will be included as part of the Draft Project Assessment Report. This report represents the second stage of the consultation process in relation to the application of the RIT-D. UE intends to publish the Draft Project Assessment Report in July UE: Demand Side Engagement Document. Available at: 25 If you do not want your submission to be publically available, please clearly stipulate this at the time of lodgement. Page 30 of 33

32 9 Abbreviations and Glossary Abbreviations AEMO Australian Energy Market Operator DAPR Distribution Annual Planning Report DMA Dromana zone substation DPAR Draft Project Assessment Report DSED Demand Side Engagement Document FPAR Final Project Assessment Report HGS Hastings zone substation MTN Mornington zone substation NEM National Electricity Market NER National Electricity Rules NNOR Non Network Options Report PoE Probability of Exceedance PSSE Power System Simulator for Engineers RBD Rosebud zone substation RIT-D Regulatory Investment Test for Distribution STO Sorrento zone substation TBTS Tyabb Terminal Station UE United Energy Distribution Pty Ltd VCR Value of Customer Reliability Page 31 of 33

33 Glossary Term Definition 1-in-2 peak day The 1-in-2 peak day demand projection has a 50% probability of exceedance (PoE). This projected level of demand is expected, on average, to be exceeded once in two years. 1-in-10 peak day The 1-in-10 peak day demand projection has a 10% probability of exceedance (PoE). This projected level of demand is expected, on average, to be exceeded once in ten years. Credible option An option that: Addresses the identified need ; Is commercially and technically feasible; and Can be implemented in sufficient time to meet the identified need. Expected Energy at Risk The expected amount of energy that cannot be supplied each year because there is insufficient capacity to meet demand, taking into account equipment unavailability and load-at-risk. Identified need Any capacity or voltage limitation on the distribution system that will give rise to Expected Energy at Risk. Limitation Any limitations on the operation of the distribution system that will give rise to expected energy at risk. Network option A means by which an identified need can be fully or partly addressed by expenditure on the distribution asset. Non-network option A means by which an identified need can be fully or partially addressed other than by a network option. Non-network service provider A party who provides a non-network option Potential credible option An option has the potential to be a credible option based on an initial assessment of the identified need. Preferred option A credible option that maximise the present value of net economic benefit to all those who produce, consume and transport electricity in the market. The preferred option can be a network option, non-network option, or do nothing (i.e. status quo). Page 32 of 33