EVALUATION REPORT RFP-ER 005/06

Transcription

1 EVALUATION REPORT RFP-ER 005/06 On reinforcement options to address projected network constraints described in RFP 005/06 Projected Distribution Network constraints: Electricity Supply to the Wudinna to Ceduna 66kV Supply Network Issue 1.0 October 2007 COPYRIGHT ETSA UTILITIES ALL RIGHTS RESERVED This document is protected by copyright vested in ETSA Utilities. No part of this document may be reproduced in any form without limitation unless prior written permission is obtained from ETSA Utilities.

2 Disclaimer This Evaluation Report has been prepared in accordance with the requirements of Section 4 of ESCOSA Guideline 12 Demand Management for Electricity Distribution Networks and of Clause of the National Electricity Rules. The purpose of the Evaluation Report is to publicly announce the outcomes of ETSA Utilities evaluation of the proposals it has received in response to a Request for Proposals it has issued and to make known the option recommended as a result of that evaluation. This document is not intended to be used by other parties for any purpose, such as making decisions to invest in generation, transmission or distribution capacity. This document has been prepared using information provided by, and reports prepared by, a number of third parties. While care was taken in the preparation of the information in this report, and it is provided in good faith, ETSA Utilities accepts no responsibility or liability for any loss or damage that may be incurred by any person acting in reliance on this information or assumptions drawn from it. ii

3 Executive Summary This Evaluation Report addresses options developed to resolve the projected network limitations described in RFP005/06 titled Projected Distribution Network constraint: Wudinna to Ceduna 66kV supply network. This RFP was issued by ETSA Utilities on 28 November No enquiries were received in response to RFP005/06. ETSA Utilities has developed a preferred network augmentation option and a second option based on a generic embedded generation solution for Tarlton and Wudinna. These options are: 1. Install a new 20MVA 66kV regulator and 66kV switchgear at Tarlton substation. 2. Construct a distillate fuelled power station at Ceduna Substation totalling up to approximately 2MW to defer the network augmentation option. These options were subjected to the Regulatory Test promulgated by the AER as required under Guideline 12. In accordance with the requirements of the Regulatory Test, market scenarios were developed to test the robustness of the test to variations in load forecast, capital and operating costs, discount rate, the cost of electrical losses, and the value of electricity to consumers (VEC). The results of this analysis show Option 1 to be the lowest net present value cost to consumers in all 13 market scenarios examined. The ranking of the development options was indifferent to reasonable variations in discount rate, load forecast, capital cost, operating costs, VEC, and cost of losses. Based on the market scenario analysis undertaken in response to the RFP proposals, Option 1 satisfies the Regulatory Test and is recommended for implementation. The annualised cost to electricity consumers of implementing this project is estimated at $382,000 per annum for the Wudinna to Ceduna 66kV supply network, which comprises depreciation, Return on Asset charges, and operating and maintenance costs. For the purposes of this report it was assumed that the relevant development and environmental approvals can be obtained for any of these options. Based on the results of this Evaluation Report and the requirements of Guideline 12, ETSA Utilities is now in a position to make its investment decision. iii

4 Table of Contents 1. INTRODUCTION NETWORK AUGMENTATION CONSULTATION PROCESS BACKGROUND ESCOSA GUIDELINE THE ELECTRICITY SUPPLY TO THE WUDINNA TO CEDUNA NETWORK NATIONAL ELECTRICITY RULES THE REGULATORY TEST EVALUATION OF PROPOSALS EXISTING SYSTEM DESCRIPTION LOAD FORECAST AND SHAPE PLANNING CRITERIA SERVICE STANDARDS / QOS Reliability standards Voltage levels and Quality of Supply PROJECTED NETWORK LIMITATION Wudinna to Ceduna line voltage levels during peak load periods OPTIONS FOR REINFORCEMENT PROPOSALS RECEIVED IN RESPONSE TO RFP OPTIONS TO ADDRESS CONSTRAINTS Tarlton Option 1: Upgrade Tarlton Substation Tarlton Option 2: Ceduna Power Station MARKET SCENARIOS CONSIDERED BASE CASE SCENARIO Discount Rate Project costs Operating and Maintenance Costs Depreciation Electricity forecast Cost of losses Value of Electricity to Consumers (VEC) MARKET SCENARIOS EVALUATED Base Case Case 1: Low Load Growth Case 2: High Load Growth Case 3: VEC = $12,000/MWh Case 4: VEC = $56,000/MWh Case 5: Cost of Losses = $50/MWh Case 6: Cost of Losses = $25/MWh Case 7: Capital Cost of Generation 120% Case 8: Operating Cost of Generation 120% Case 9: Capital Cost of Network Augmentations 120% Case 10: Capital Cost of Network Augmentations 90% Case 11: Discount Rate = 7.13% Case 12: Discount Rate = 12% EVALUATION OF PROPOSALS MARKET SCENARIO ANALYSIS DISCUSSION...21 iv

5 8. SUMMARY AND CONCLUSIONS...22 v

6 Definitions Act Electricity Act 1996 AER Application Notice Base Case Demand Management (DM) DNSP DSM DUOS EDC ESCOSA ESDP ETSA Utilities Guideline 12 (GL 12) Interested Party Australian Energy Regulator A notice made available to Registered Participants and Interested Parties pursuant to clause of the NER The market scenario considered most probable to be realistic when undertaking the Regulatory Test which is used as the reference case when considering alternative plausible market scenarios Demand Management is the management of the level or pattern of energy use on the transmission / distribution network, so as to minimise the supply cost to customers whilst maintaining or enhancing customer service levels. Supply costs include costs of projects associated with the augmentation of, or extension to, the transmission or distribution network, and include network losses Distribution Network Service Provider Demand Side Management the management of demand on the power system by means of controlling or reducing the load on the network Distribution Use of System charges applicable to Registered Participants in the NEM Electricity Distribution Code (EDC) as issued by ESCOSA Essential Services Commission of South Australia established under the Essential Services Commission Act 2002 Electricity System Development Plan (ESDP) developed annually by ETSA Utilities and published by 30 June. The ESDP includes details of projected limitations on the ETSA Utilities Distribution system for at least the next three year period and provides the information needed for a party to register as an Interested Party as defined within ESCOSA Guideline 12 ETSA Utilities is South Australia s principal Distribution Network Service Provider (DNSP), and is responsible for the distribution of electricity to all distribution grid connected customers within the State under a regulatory framework. ETSA Utilities is a partnership of Cheung Kong Infrastructure Holdings Ltd (CKI), Hong Kong Electric International Ltd (HEI) and Spark Infrastructure ESCOSA Electricity Industry Guideline 12 Demand Management for Electricity Distribution Networks Individuals or organisations registered with ETSA Utilities in vi

7 NEM NEMMCO NER NPV O&M OLTC QOS RDP Reasonableness Test Registered Participant Regulatory Test RFP ROA Rules TUOS SAIDI SAIFI VEC VoLL WACC accordance with Guideline 12 that have an interest in ETSA Utilities long term planning, Demand Management initiatives, addressing a particular constraint, or more generally in addressing Demand Management issues National Electricity Market National Electricity Market Management Company Limited National Electricity Rules Net Present Value Operating and Maintenance On Load Tap Changer a device used to control the output voltage of a transformer Quality of Supply Regional Development Plan Reasonableness Test - as defined in ESCOSA Electricity Industry Guideline 12 A person who is registered with NEMMCO as a Network Service Provider, a System Operator, a Network Operator, a Special Participant, a Generator, a Customer or a Market Participant The test promulgated by the AER, which all major network investment must comply with Request for Proposals Return on Asset National Electricity Rules (NER) Transmission Use of System charges applicable to Registered Participants in the NEM System Average Interruption Duration Index System Average Interruption Frequency Index. Value of Electricity to Consumers Value of Lost Load as measured in the NEM Weighted Average Cost of Capital vii

8 1. INTRODUCTION ETSA Utilities continually monitors the performance of its power system and analyses the capability of the system to reliably and economically meet existing and future load requirements. Through this monitoring and analysis the need for future augmentation, upgrading or modifications to the distribution system can be identified and implemented in a timely manner. As a result of its analysis ETSA Utilities has identified a possible Eligible Major Network Project to upgrade the Wudinna to Ceduna 66kV supply network due to voltage limitations during peak load times in 2011/12. The ETSA Utilities Eyre Region includes the region from Port Augusta extending south-west to Yalata. Most of the area west of Cleve on the Eyre Peninsular is supplied via a radial 66kV line from the ElectraNet Wudinna connection point substation. The geographic region of the State that is being considered is located in the Eyre Peninsula and includes the townships of Ceduna, Moorkitabie, Minnipa, Smoky Bay and Streaky Bay. Ceduna is located approximately 430km northwest of Port Lincoln, located on the coast of Denial Bay, and is supplied by a 208km long 66kV line from Wudinna via Tarlton. The electrical load in this section of the Eyre Peninsular is a mix of agricultural, aquaculture and tourism, with residential and tourism customers comprising the local township loads. Recent growth has been in the tourism and aquaculture industry at Smoky Bay and Streaky Bay with future growth in coastal housing developments at Streaky Bay. Demand forecasts issued by ETSA Utilities for the Wudinna to Ceduna supply network provide an overall load growth in the area at an average rate of 2.5% per annum expecting to increase from 16.7MVA in 2011/12 to 21.2MVA in 2021/22. This growth represents the moderate forecast which ETSA Utilities uses for planning purposes. Customer voltage levels are expected to be below the Electricity Distribute Code limits on the Wudinna to Ceduna 66kV supply network during peak load times in 2011/12. 1

9 Figure 1a: Wudinna to Ceduna Electricity Supply System 2

10 2. NETWORK AUGMENTATION CONSULTATION PROCESS 2.1 Background Prior to undertaking an augmentation of its power system that involves a significant level of expenditure ETSA Utilities is required to consult with affected parties, Registered Participants and Interested Parties under the National Electricity Rules (NER) and ESCOSA Guideline 12. The consultation process that is being followed by ETSA Utilities has been structured to meet the needs of both the NER and ESCOSA Guideline 12 and involves the annual issue of an Electricity System Development Plan (ESDP), undertaking a Reasonableness Test where required, and if the Reasonableness Test is met, issuing a Request for Proposal (RFP) seeking alternative solutions to the projected distribution network limitation. 2.2 ESCOSA Guideline 12 Under ESCOSA Guideline 12 ETSA Utilities prepares an annual ESDP that identifies actual and forecast constraints on the ETSA Utilities power system for the approaching three year period. The ESDP details existing and projected distribution system limitations for the 13 regions presently covered by ETSA Utilities regional development plans and is published on 30 June each year. ETSA Utilities is required to issue an RFP for all (except where exemption granted) Eligible Major Network Projects that meet the Reasonableness Test. The RFP must be placed on the ETSA Utilities web site, issued to all Interested Parties, and publicly advertised in local newspapers in general circulation in SA. The typical consultation process undertaken by ETSA Utilities involves the annual publication of the ESDP, which includes details of existing and projected network limitations. This is followed by undertaking a Reasonableness Test as required by Guideline 12 and issuing a Request for Proposals for Eligible Major Network Projects. It is a requirement of Guideline 12 that all compliant submissions received in response are to be evaluated in the Evaluation Report. 2.3 The Electricity Supply to the Wudinna to Ceduna network ETSA Utilities published RFP005/06 Projected Distribution Network Constraint: Electricity supply to the Wudinna to Ceduna Supply Network on its web site on 28 November RFP005/06 closed for submissions on 22 May Relevant information regarding the existing system and network limitations is provided in Section 3 of this report. 3

11 2.4 National Electricity Rules Clause of the National Electricity Rules (NER) also places obligations on a Distribution Network Service Provider (DNSP) such as ETSA Utilities to consult with Registered Participants and Interested Parties (as those terms are defined in the NER) regarding augmentations and extensions to the distribution system. The process being followed by ETSA Utilities has been designed to comply with the consultation requirements of both ESCOSA Guideline 12 and the NER. 2.5 The Regulatory Test ESCOSA Guideline 12 details the evaluation process that must be used when assessing compliant responses to an RFP. Specifically this evaluation process must take into account all relevant costs and benefits and must also comply with the AER s Regulatory Test for Network Investment. The Regulatory Test was prepared by the AER and is promulgated under clause 5.6.5A of the NER. The Regulatory Test considers two basic types of augmentation in its application. The first of these types relates to augmentations that are proposed to enhance the operation of the National Electricity Market (NEM) and can be justified in terms of net benefit to the market or market benefit. The second type relates to augmentations that are proposed to meet objectively measurable service standards linked to the technical standards contained within the NER and any specific jurisdictional requirements. This latter type of augmentation is referred to as a reliability augmentation. A reliability augmentation satisfies the Regulatory Test if the augmentation minimises the net present value of the cost of meeting the relevant services standards in most, but not necessarily all, reasonable scenarios. In this case cost means the total cost of the augmentation to all those that produce, distribute, and consume electricity in the NEM. The NER specifically requires network performance to comply with what is regarded as Good Electricity Supply Industry Practice, and to meet system security requirements. At the distribution level, system security mainly relates to keeping plant and equipment within designated ratings for both normal and credible contingency events. Supply quality, such as maintaining voltages within acceptable levels, is also addressed within the NER and is another driver associated with network augmentation. It is a jurisdictional requirement under ESCOSA Guideline 12 that ETSA Utilities publish its power system planning criteria in the annual ESDP. These planning criteria are designed to meet the reliability, technical, and quality of supply requirements contained within the NER and the SA Electricity Distribution Code (EDC). As such, ETSA Utilities planning criteria also represent an objectively measurable service standard and developing the power system to comply with these standards constitutes a reliability augmentation. The Regulatory Test requires that the net present value calculations use a discount rate appropriate for the analysis of a private enterprise investment in the electricity sector. The Regulatory test also requires sensitivity analysis to be undertaken with respect to the key input 4

12 variables, which includes capital and operating costs, the discount rate and the commissioning date in order to demonstrate the robustness of the analysis. The majority of network augmentation proposed by a Distribution Network Service Provider falls into the category of a reliability augmentation. The following matters need to be considered when determining the NPV of costs associated with a reliability augmentation: 1. The cost of the project; 2. The costs or benefits of changes in electrical losses; 3. Reasonable forecasts of: a) Electricity demand (load); b) The value of electricity to consumers (as reflected in VEC); c) Capital costs for committed, anticipated, or future projects and whether these capital costs can be completely or partially avoided or deferred; d) O&M costs for committed, anticipated, or future projects; and e) Any other costs associated with a project, e.g. Financially measurable environmental costs or benefits, or additional market operating costs (e.g. ancillary services); 4. The timing of the augmentation (and how this may be influenced by load forecasts etc); 5. A reasonable range of alternative market development scenarios incorporating varying levels of demand growth (reflecting DSM options), alternative project commissioning dates, and various generator investment options; and 6. The Regulatory test analysis should be over a reasonably long time frame. The Wudinna and Tarlton system augmentation is needed to ensure the loading on plant and equipment remains within industry accepted limits and the limits prescribed by the NER and EDC. As such the Wudinna and Tarlton system augmentation falls into the category of a reliability augmentation and must satisfy the regulatory test in this regard. 2.6 Evaluation of proposals ETSA Utilities is required to evaluate the proposals it obtains in response to a RFP in accordance with the provisions of the AER s Regulatory Test (refer to section 4.1 of Guideline 12). It is then required to publicly announce the results of this evaluation. Where an RFP has been issued and/or where alternatives to an RFP are proposed, all conforming Proposals and options must be evaluated by ETSA Utilities. Conforming options developed by ETSA Utilities are also evaluated at this time. ETSA Utilities evaluation of the options includes the following: 1. Options (and where necessary groups of options) are evaluated and ranked on the basis of the total net annualised costs of system support incurred by ETSA Utilities, plus the 5

13 cost or benefits of changes to transmission and distribution losses. Total net annualised costs of system support incurred by ETSA Utilities includes all capital, fixed, variable and operating costs of securing the specified level of system support; 2. System support is measured in terms of kva of constrained peak capacity, $/kva of constrained peak capacity and the period of constraint; 3. A ten-year period for evaluation has been used in this particular case; 4. External costs are included in the evaluation of any option wherever these reflect an existing or anticipated regulatory obligation of ETSA Utilities, as specified by the AER s Regulatory Test; and 5. The relative intrinsic risks, including the likely impact on system reliability and quality of supply, of specific options and technologies have been assessed in accordance with normal commercial practice. 6

14 3. EXISTING SYSTEM 3.1 Description The ETSA Utilities Eyre Region includes the region from Port Augusta extending south-west to Yalata. Most of the area west of Cleve on the Eyre Peninsular is supplied via a radial 66kV line from the ElectraNet Wudinna connection point substation. The area between Wudinna and Ceduna is supplied by 208km of 66kV line emanating from the ElectraNet Wudinna 132/66kV connection point substation. The line supplies ETSA Utilities 66/11kV substations at Tarlton, Moorkitabie, Wudinna, Ceduna, and Streaky Bay. End of line low feeder voltage levels are boosted via 66/11kV OLTC transformers located at Ceduna and Streaky Bay substations. The Wudinna Substation is located approximately 2km from the Wudinna silos, on Cocata Road. Wudinna Substation is supplied via the ElectraNet 132kV electricity distribution system. The Wudinna Substation consists of one 132/66kV 25MVA transformer which is supplied via a 132kV transmission line from Yadnarie Substation. 3.2 Load forecast and shape The growth in electrical load in a region is dependent upon many variables including economic growth, housing and commercial development, industrial growth, spot load increases that occur in response to local requirements, and environmental conditions (predominately weather conditions). The forecasting of electrical load is based upon econometric analysis coupled with knowledge of localised developments and historical information and trends. Load forecasts are reviewed annually and also when significant changes in circumstances occur. The load forecast provided below is subject to review and may alter as a consequence of this ongoing review within the time frames associated with this consultation process. Demand forecasts issued by ETSA Utilities for the Wudinna to Ceduna supply network provide an overall load growth in the area at an average rate 2.5% per annum expecting to increase from 16.7MVA in 2011/12 to 21.2MVA in 2021/22, as shown in Table 1. This growth represents the moderate forecast which ETSA Utilities uses for planning purposes. 7

15 Year Wudinna 11kV Moorkitabie Tarlton Streaky Bay Ceduna Wudinna Total Total Diversified 2011/ / / / / / / / / / / Table 1: Moderate forecast total electricity demand at summer peak levels for the Wudinna to Ceduna 66kV Supply Network values in MVA. The above forecast takes into account any known demand management programmes in-place or committed, and any known embedded generation that may reduce the forecast of demand that needs to be supplied via each substation, provided these load reduction solutions are continuously available at times of peak load. The electrical load in the Wudinna to Ceduna region comprises mainly rural residential customers, but also includes commercial enterprises. However, significant numbers of new housing developments along the coast at Ceduna and Streaky Bay have contributed to a high electricity load growth rate for the area. The following graphs show the annual load duration curves for the Wudinna to Ceduna supply area and the daily load curve for the summer and winter peak load day. 8

16 Wudinna to Ceduna Load Duration Curve % Load % Time Figure 2: Cumulative load duration Wudinna to Ceduna between 13/09/05 and 13/9/06 1 Summer Winter Per Unit :00 AM 2:00 AM 4:00 AM 6:00 AM 8:00 AM 10:00 AM 12:00 PM 2:00 PM 4:00 PM 6:00 PM 8:00 PM 10:00 PM 12:00 AM Time of Day Figure 3: Daily load profile for the Wudinna to Ceduna 66kV Line during summer 2005/06 (20 January 2006) and winter 2006 (13 July 2006) 9

17 3.3 Planning criteria As a Network Service Provider (NSP) within the National Electricity Market, ETSA Utilities must comply with technical standards in the National Electricity Rules. In particular, requirements relating to reliability and system security contained in Schedule 5.1 of the Rules are relevant to planning for future electricity needs. In addition, as licensed electricity entities in South Australia, ETSA Utilities is required to comply with the service obligations imposed by the South Australian Electricity Distribution Code (EDC). ETSA Utilities is required to operate its power system within plant ratings and with acceptable quality of supply under reasonably expected operating conditions in order to comply with its requirements under the NER and the EDC. These planning criteria are included in the annual Electricity System Development Plan for ETSA Utilities Distribution System that is published annually on 30 June. These planning criteria include: A standard customer supply voltage of 230V with an upper limit of 253V (230V plus 10%) and a lower limit of 216V (230V minus 6%). Due to long 11kV feeders in the region 11kV substation bus voltage levels must be maintained at 1.00pu to achieve satisfactory customer voltage at the extremities of these feeders. Full details of the projected distribution network limitations applying to the Wudinna to Ceduna 66kV electricity supply system, were contained in the ESDP issued on 30 June 2006, and RFP005/06 that was issued to Interested Parties in November The projected network limitations applicable to the Wudinna to Ceduna supply network are summarised in section 3.5 below. 3.4 Service standards / QOS The relevant region of South Australia covered by this RFP is categorised as rural (for the purposes of the Service Standards contained within the EDC (refer to clause 1.2 of that Code). The following service standards are applicable to the region. Response and restoration times Commitment Time to respond to telephone calls Time to respond to written enquiries Time to provide written explanation for interruptions to supply Time to restore supply to rural areas Standard 85% within 30 seconds (excluding calls after a major outage event) 95% within 5 business days 85% within 20 business days 80% within 3 hours 90% within 5 hours 10

18 Reliability standards Area Supplied Average Minutes Off Supply (Number of minutes without supply on average per annum) Average Number of Supply Interruptions per customer (Number of supply interruptions experienced on average per customer per annum) Upper North / Eyre Peninsula Voltage levels and Quality of Supply ETSA Utilities must ensure that its distribution system meets the voltage and quality of supply limits specified in section of the EDC, that is: ETSA Utilities must ensure that its distribution network is designed, installed, operated and maintained so that: at the customer s supply address: the voltage is as set out in AS 60038; the voltage fluctuations that occur are contained within the limits as set out in AS/NZS Parts 3.3 and 3.5 and AS2279 Part 4; and the harmonic voltage distortions do not exceed the values in AS/NZS Part 3.2 and AS 2279 Part 2 and as set out in the schedule to the standard connection and supply contract; and the voltage unbalance factor in 3 phase supplies does not exceed the values set out in the schedule to the standard connection and supply contract. ETSA Utilities must ensure that any interference caused by its distribution network is less than the limits set out in AS/NZS Part 3.5 and AS/NZS In addition to meeting the above EDC service standards ETSA Utilities is required to operate its Distribution System in accordance within the technical and system security standards contained within the NER, and plan and develop its network in accordance with the planning criteria mentioned in section

19 3.5 Projected network limitation Wudinna to Ceduna line voltage levels during peak load periods The forecast peak load in summer 20011/2012 on the Wudinna to Ceduna 66kV supply network will result in unsatisfactory customer voltage levels. Any proposals aimed at addressing the projected voltage limitations will need to effectively increase and maintain voltage levels to acceptable levels at the stated load growth rate and with unforeseen large customer spot load increases. The following table provides an indication of the projected voltage level at strategic locations on the Wudinna to Ceduna 66kV supply network in per unit values. Table 4: Wudinna to Ceduna Projected Voltage Levels in Per Unit (PU) Year Wudinna 66kV Moorkitabie 66kV Tarlton 66kV Streaky Bay 66kV Ceduna 66kV Ceduna 11kV 2006/ / / / / / The following Table 5 provides an indication of the level and period of load reduction required to ensure adequate customer voltage levels are maintained throughout the 66kV supply network. Moderate Load growth Rating Load at Risk Year Load MVA MVA Load at risk % Load at Risk No Hours* 2011/ % / % / % / % / % / % / % / % / % / % / % 94 12

20 * To allow for time to dispatch any demand management solution, 32 hours have been added to the duration at risk. This is based on the approach that the demand management will have to be pre-dispatched during a 4-day heatwave and will be required for 8 hours runtime per day during the heatwave. It is important to note that distribution network losses are not included in the above forecast. These losses are estimated to be around 24% of the total MVA load in 2011/12. The type and location of a proposed solution may influence the distribution network losses. 13

21 4. OPTIONS FOR REINFORCEMENT 4.1 Proposals received in response to RFP No Proposals were received in response to the projected distribution network limitations contained in RFP005/ Projected Distribution Network Constraint: Wudinna to Ceduna 66kV supply network. ETSA Utilities considers that an embedded generation proposal is highly unlikely to be economic to address the network limitations on the Wudinna to Ceduna network. However, in order to appropriately test this view, ETSA Utilities has developed a generic generation proposal which assumes suitable sites and all approvals can be obtained and subjected this to the Regulatory Test. 4.2 Options to address constraints ETSA Utilities has developed a preferred network augmentation option and a second option based on a generic embedded generation solution for Ceduna. These options are: 1. Install a new 20MVA 66kV regulator and 66kV switchgear at Tarlton substation. 2. Construct a distillate fuelled power station at Ceduna Substation totalling up to approximately 2MW to defer the network augmentation option. These options are described in more detail in the following sections Tarlton Option 1: Upgrade Tarlton Substation This option involves installing a new 20MVA 66kV regulator and 66kV circuit breaker, and associated protection, control and SCADA equipment at Tarlton substation. The estimated cost of this project is $2.9M. For the purposes of this report it is assumed that the relevant development and environmental approvals can be obtained for this project Tarlton Option 2: Ceduna Power Station This option involves the construction of a distillate-fired power station at Ceduna Substation in This generation option is based on installing generating units with adequate capacity to last until 2017 (based on moderate load growth scenario). During 2017 the upgrading of the Tarlton Substation with the installation of a 20MVA 66kV regulator and associated 66kV switchgear will be completed replacing the generation. The estimated cost of this initial stage of development is $8.1M in 2011, $1.5M in 2014, and the final stage estimated at an additional $2.9M with approximately $0.85M of plant recovered when the generators are removed. For the purposes of evaluating this report, it has been assumed the generating units would be pre-dispatched to avoid the risk of customer outages and generate the equivalent amount of energy needed to supply the load deficit based upon the load duration characteristic of the Wudinna to Ceduna distribution system. 14

22 5. MARKET SCENARIOS CONSIDERED The Regulatory Test that has been promulgated by the AER states that for system capacity upgrade augmentations (as is the case for the projected limitations in the Tarlton and Wudinna system), requires that the recommended option be the option with the lowest net present value cost under the majority of market development scenarios considered. Clause 5.6 of the NER states that the minimum planning period for the purposes of the annual planning review is 5 years for distribution networks and 10 years for transmission networks. Clause also states that the relevant Distribution Network Service Provider must consult with affected Registered Participants and interested parties on the possible options, including but not limited to demand side options, generation options and market network services provider options to address the projected limitations of the relevant distribution system. In line with the requirements of the Regulatory Test and the NER consideration has been given to a non-network option. For the purposes of the NPV analysis a time frame of 10 years has been selected. All augmentations and alternative developments considered will provide an adequate electricity supply to the Wudinna to Ceduna network up until at least 2017/ Base Case scenario The Base Case market scenario was developed to represent the most likely market scenario that would eventuate. Several possible variations of this Base Case scenario where then formulated to assess the sensitivity of the Regulatory Test to potential market variations. The Base Case scenario was developed assuming the following information Discount Rate The regulatory test requires the NPV analysis to use a discount rate appropriate for the analysis of a private enterprise investment in the electricity sector. From a review into the Regulatory Test for network augmentation the AER concluded that: the regulatory WACC might reasonable be considered the lower boundary of the discounts rate but not the mean value around which sensitivity testing is conducted ; and the discount rate adopted for the purpose of the regulatory test evaluation should be a commercial discount rate in order to ensure network and non-network investments are compared on a competitively neutral basis. ETSA Utilities has undertaken some work with consultants and determined that the appropriate real pre-tax weighted average cost of capital for non regulated work is between 10 and 15 percent. In assessing whether one should apply a rate at the lower or higher end of that range various factors should be taken into consideration such as - the period of the investment, counterparty risk, size, complementary business opportunities and other risk strategies and adjustments. 15

23 In ETSA Utilities view it would be reasonable to use a range between the regulatory WACC (7.13%) and 12% as real pre-tax weighted average cost of capital. For the Base Case a discount rate of 10% has been utilised in the economic evaluation. This rate has been reflected in the Return on Asset charges (ROA) associated with each augmentation option. Sensitivity analysis has been undertaken assuming a discount rate of 7.13% and 12% Project costs ETSA Utilities has prepared cost estimates for the work it would have to undertake for each augmentation option. These costs, in addition to the costs associated with work undertaken by other parties associated with an augmentation option have been used in undertaking the Regulatory Test. In the base case scenario, the costs, as estimated, have been used with sensitivity analysis undertaken on these costs for other market scenarios. Because Option 2, the Power Station solution, uses different technology to augment the power supply system compared to Option 1, the capital cost of Option 2 has been varied independently of the alternative development in the sensitivity analysis. The project costs used are based on 2007 dollar values and don t include any allowance for risk or contingencies Operating and Maintenance Costs In Option 1 the operating and maintenance costs have been derived as a fixed proportion of capital cost. As a consequence, a variation in capital costs would be the equivalent to separately varying the operating and maintenance cost. However, because Option 2 uses different technology with a different operating and maintenance regime to Option 1, the sensitivity of the regulatory test analysis has been separately assessed based upon fuel and O&M costs increasing 20% above the estimated level. In addition the generator operating costs were reduced by assuming the generated power would be sold into the National Electricity Market. Since the generators would be dispatched for system support reasons, the energy sale price used was the same as that used for the losses calculation Depreciation In all cases the capital cost was depreciated in a straight line over the regulatory asset lives. Each project was split into three cost components and each component was depreciated according to the following asset lives: Lines = 55 years Substations = 45 years Generators = 20 years 16

24 Electricity forecast For the Base Case market scenario the load growth for the Wudinna to Ceduna 66kV supply network contained in the June 2006 ESDP was used. This has been referred to as the Medium Load growth rate. Variations of between +18% and -18% on this growth rate have been used in other market scenarios studied Cost of losses Guideline 12 requires the cost of electrical losses to be considered when evaluating options. Network analysis has been utilised to estimate the electrical losses associated with each augmentation option under consideration relative to the existing supply arrangement. The Base Case for valuing electrical losses examines the cost to electrical consumers as determined by the average pool price in South Australia during 2006 (approximately $39 per MWh). Sensitivity analysis was undertaken on this assumption based on a cost of losses of $50/MWh and $25/MWh Value of Electricity to Consumers (VEC) The Regulatory Test permits the Value of Electricity to Consumers (VEC) as measured in the NEM to be included in the analysis. In cases where an augmentation reduces the number and duration of customer outages a credit would be applied against the project to reflect the increased reliability benefits being obtained by the end users. Research undertaken by Monash University in Victoria in the 1997 and updated by Charles River and Associates (CRA) in indicated that the value a consumer placed on their electricity supply varied significantly with the market sector. The CRA report calculated a state level VEC value based on a weighting factor used to weight each sector VEC based on the total electricity consumed by that sector. In the Victorian situation the weighted average value placed on electricity supply by all market sectors was valued at about $29,600/MWh. The value placed on supply reliability by a market sector as determined by the CRA and Monash survey is based on the following factors, Cost of operating back-up electrical equipment; Loss/spoilage of products, raw materials, livestock, dairy, eggs, fruit or vegetable products; Damage to plant and equipment; Lost productivity; Restart/make up/repair costs; and Forgone sales. Costs associated with a loss of electricity supply within individual market sectors can vary considerably using the above considerations. For metropolitan areas the Victorian state 1 CRA Final Report - Assessment of the Value of Customer Reliability (VCR) December

25 average VEC of $29,600/MWh was chosen for the Bases Case. Sensitivity analysis has been undertaken assuming VEC = $12,000/MWh (Residential) and $56,000/MWh (Commercial). 5.2 Market scenarios evaluated In order to determine the augmentation option that satisfies the Regulatory Test a total of 13 credible market scenarios have been developed including the Base Case. The augmentation option which is ranked the least NPV cost option under most but not necessarily all scenarios will satisfy the Regulatory Test and the requirements of Guideline 12. The following market scenarios were examined Base Case The Base Case market scenario considers, Medium Load Forecast Discount Rate = 10% $29,600/MWh The Cost of $39/MWh Generator capital costs as estimated Generator operating costs as estimated Network capital and operating costs as estimated Case 1: Low Load Growth Case 1 is identical to the Base Case but assumes that the load growth on the Wudinna to Ceduna 66kV supply network is 18% lower than the medium forecast rate Case 2: High Load Growth This market scenario is identical to the Base Case but assumes that the load growth on the Wudinna to Ceduna 66kV supply network is 18% higher than the medium forecast Case 3: VEC = $12,000/MWh This scenario is identical to the Base Case but assumes that VEC has been decreased to $12,000/MWh Case 4: VEC = $56,000/MWh This scenario is identical to the Base Case but assumes that VEC has been increased to $56,000/MWh Case 5: Cost of Losses = $50/MWh This scenario is the same as the Base Case but assumes that the Cost of Losses is equal to $50/MWh. 18

26 Case 6: Cost of Losses = $25/MWh This scenario is the same as the Base Case but assumes that the Cost of Losses is equal to $25/MWh Case 7: Capital Cost of Generation 120% This scenario is the same as the Base Case but assumes that the capital cost associated with Option 2, the Power Stations are 20 % higher than estimated Case 8: Operating Cost of Generation 120% This scenario is the same as the Base Case but assumes that the fuel costs associated with Option 2 are 20 % higher than estimated Case 9: Capital Cost of Network Augmentations 120% This scenario is the same as the Base Case but assumes that the capital cost associated with the network augmentations of Option 1 is 20% higher than estimated Case 10: Capital Cost of Network Augmentations 90% This scenario is the same as the Base Case but assumes that the capital cost associated with the network augmentations of Option 1 is 10 % lower than estimated Case 11: Discount Rate = 7.13% This scenario is the same as the Base Case but assumes that Discount Rate = WACC = 7.13% Case 12: Discount Rate = 12% This scenario is the same as the Base Case but assumes that Discount Rate = 12%. 19

27 6. EVALUATION OF PROPOSALS 6.1 Market scenario analysis A summary of the outcome of the market scenario analysis for the 13 cases (including the Base Case) appears in the following tables. Base Case Most Likely NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$110,514 -$51,267 $0 $1,594,804 $2,096,295 1 Option B $2,811,467 $1,068,446 -$108,328 -$19,774 $0 $4,623,201 $8,375,012 2 Case 1 - Low Load Growth NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $337,397 $227,743 -$51,156 -$47,445 $0 $1,370,766 $1,837,305 1 Option B $1,985,923 $760,477 -$49,578 -$9,604 $0 $3,333,329 $6,020,547 2 Case 2 - High Load Growth NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$231,131 -$49,899 $0 $1,594,804 $1,977,046 1 Option B $2,895,825 $1,084,957 -$229,070 -$18,703 $0 $4,936,982 $8,669,990 2 Case 3 - VEC = $12,000 NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$44,803 -$51,267 $0 $1,594,804 $2,162,006 1 Option B $2,811,467 $1,068,446 -$43,917 -$19,774 $0 $4,623,201 $8,439,424 2 Case 4 - VEC = $56,000 NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$209,081 -$51,267 $0 $1,594,804 $1,997,728 1 Option B $2,811,467 $1,068,446 -$204,945 -$19,774 $0 $4,623,201 $8,278,395 2 Case 5 - COL = $50/MW.h NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$110,514 -$65,727 $0 $1,594,804 $2,081,835 1 Option B $2,811,467 $1,068,446 -$108,328 -$25,351 $0 $4,623,201 $8,369,435 2 Case 6 - COL = $25/MW.h NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$110,514 -$32,864 $0 $1,594,804 $2,114,698 1 Option B $2,811,467 $1,068,446 -$108,328 -$12,676 $0 $4,623,201 $8,382,111 2 Case 7 - Gen Capital = 120% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$110,514 -$51,267 $0 $1,594,804 $2,096,295 1 Option B $3,350,698 $1,230,216 -$108,328 -$19,774 $0 $5,449,553 $9,902,365 2 Case 8 - Gen Operating = 120% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $395,983 $267,289 -$110,514 -$51,267 $0 $1,594,804 $2,096,295 1 Option B $2,811,467 $1,104,799 -$108,328 -$19,774 $0 $4,623,201 $8,411,365 2 Case 9 - Network Capital = 120% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $475,180 $320,746 -$110,514 -$51,267 $0 $1,913,765 $2,547,910 1 Option B $2,834,529 $1,084,013 -$108,328 -$19,774 $0 $4,721,490 $8,511,930 2 Case 10 - Network Capital = 90% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $356,385 $240,560 -$110,514 -$51,267 $0 $1,435,324 $1,870,487 1 Option B $2,799,936 $1,060,663 -$108,328 -$19,774 $0 $4,574,057 $8,306,554 2 Case 11 - Discount Rate =7.13% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $449,923 $303,698 -$133,026 -$58,817 $0 $1,285,225 $1,847,004 1 Option B $3,214,954 $1,220,191 -$130,571 -$24,355 $0 $3,747,683 $8,027,902 2 Case 12 - Discount Rate =12% NPV Option Depreciation O&M VEC Losses TUOS ROA - Distribution Total Rank Option A $364,125 $245,785 -$97,626 -$46,833 $0 $1,765,951 $2,231,403 1 Option B $2,574,013 $978,885 -$95,604 -$17,181 $0 $5,099,294 $8,539,

28 7. DISCUSSION In all cases analysed Option 1, the installing of a 20MVA 66kV regulator (with associated 66kV switchgear) at Tarlton Substation represent the least cost option were ranked as the least cost project. The sensitivity analysis shows that the ranking of options is insensitive to variations in capital and operating costs and to variations in the discount rate within reasonably expected bounds. The ranking of projects remains unchanged for a discount rate between 7.13% and 12%. For the purposes of this report it was assumed that the relevant development and environmental approvals can be obtained for any of the options identified. 21

29 8. SUMMARY AND CONCLUSIONS A total of 2 augmentation options and 13 market scenarios were analysed in undertaking the Regulatory Test for the Overload of the Wudinna to Ceduna supply network RFP005/06. The results of this analysis shows that Option 1 ie the installing of a 20MVA 66kV regulator (with associated 66kV switchgear) at Tarlton Substation represent the least cost option that addresses the projected network limitations. The ranking of the augmentation options was indifferent to reasonable variations in discount rate, load forecast, capital cost, operating costs, VEC, and cost of losses. Based on the market scenario analysis undertaken in response to the RFP005/06, Option 1 satisfies the Regulatory Test and is recommended for implementation. The annualised cost to electricity consumers of implementing this project is estimated at $382,000 per annum for Tarlton, which comprises depreciation, Return on Asset charges, and operating and maintenance costs. 22