Regulatory 4 March 2011Test - Request for Information

Transcription

1 Ergon Energy Corporation Limited Regulatory 4 March 2011Test - Request for Information Emerging Distribution Network Limitations in the South Mackay Area 28 October 2013 Ergon Energy Corporation Limited Disclaimer While care was taken in preparation of the information in this discussion paper, and it is provided in good faith, Ergon Energy Corporation Limited 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. This discussion paper has been prepared for the purpose of inviting information, comment and discussion from interested parties. The document has been prepared using information provided by a number of third parties. It contains assumptions regarding, among other things, economic growth and load forecasts which may or may not prove to be correct. All information should be independently verified to the extent possible before assessing any investment proposals.

2 EXECUTIVE SUMMARY Ergon Energy Corporation Limited (Ergon Energy) is responsible (under its Distribution Authority) for electricity supply to the South Mackay area in Central Queensland. We have identified emerging limitations in the electricity distribution network supplying the South Mackay area (hereby known as the study area). The loads on Ergon Energy s zone substation and 11kV network in the study area have progressively increased such that augmentation is required if reliable supply is to be maintained. The study area is presently supplied by the South Mackay 33/11kV substation, known as SOMA. This substation is supplied from T38 Mackay. The N-1 substation rating is 20.7 MVA. The load on SOMA 33/11 kv substation exceeded the substation N-1 rating over summer 2011/12. This risk was successfully managed, but in future any transformer contingency at the peak time of year may result in customer load shedding. In order to manage the load at risk and maintain security of supply, demand reductions and/or supply-side capacity improvements totalling a minimum of 3.65MVA in the summer of 2014/15 and 4.75MVA in the summer of 2015/16 need to be achieved (subject to periodic review). Ergon Energy is seeking input for possible solutions. Large solutions, over 5MVA, will be assessed in the usual manner. In addition, a Demand Reduction Incentive Map (DRIM) has been developed for the study area and published to send pricing signals to the marketplace ($ per kva subject to business rules) that indicates the value to Ergon Energy of demand savings in the Study Area. By following the supplied business rules, customers can automatically obtain the incentives to provide demand management and/or demand response proposals. Ergon Energy actively encourages providers of non-network solutions to respond to this Request For Information with proposals for initiatives that can contribute towards meeting the demand reduction targets. All proposals received will be evaluated and where a proposal represents a viable solution at an acceptable cost and meets the business rules, the proponent will be contacted. This is a Request for Information where Ergon Energy is seeking information about possible solutions to the emerging limitations which may be able to be provided by parties other than Ergon Energy. Submissions in writing (electronic preferably) are due by 23 December 2013 and should be lodged to: Attention: Network Planning and Strategy regulatory.tests@ergon.com.au Updated information will be provided on our web site: For further information and inquiries please submit to the address above. Page 1 NA001602T100 Ver 1

3 TABLE OF CONTENTS EXECUTIVE SUMMARY INTRODUCTION BACKGROUND & PURPOSE FOR THIS REQUEST FOR INFORMATION Background Purpose of this Request for Information EXISTING SUPPLY SYSTEM TO THE SOUTH MACKAY AREA Geographic Region Existing Supply System EMERGING DISTRIBUTION NETWORK LIMITATIONS Distribution Feeder Forecast Timeframes for Taking Corrective Action Known Future Network and Generation Development INFORMATION ABOUT CRITERIA THAT SOLUTIONS MUST MEET Large Solution 5MVA Size Timing Location Network Connections Quality Reliability Longevity Small Solutions Size Timing Problem Definition Location Network Connections Agreement Quality Reliability and Longevity EVALUATION PROCESS Evaluation Criteria Submissions from Solution Providers Public Consultation Demand Reduction Incentive Map (DRIM) Timetable for Submissions Assessment and Decision Timetable Appendix A Permanent Demand Reduction Problem Definition: Demand Reduction Incentive $300/kVA Contract Call-On Generation and Call-Off Load Problem Definition: Demand Reduction Incentive $80/kVA/annum plus an agreed running or call-off $/hour, when notified Contract Page 2 NA001602T100 Ver 1

4 1. INTRODUCTION Ergon Energy has identified emerging limitations in the electricity distribution network supplying South Mackay area of Central Queensland. This is a Request for Information where Ergon Energy is seeking information about possible solutions to the emerging limitations which may be able to be provided by parties other than Ergon Energy. For large scale solutions >5MVA Submissions in writing (electronic preferred) are due by 23 December 2013 and should be lodged to: Attention: Network Planning and Strategy regulatory.tests@ergon.com.au A decision is required by 11 March 2014 if the initial stage of any option involving significant construction is to be completed by September Updated information will be provided on our web site: For small scale demand management solutions Visit Ergon Energy Empower website at for process and business rules for applying. Page 3 NA001602T100 Ver 1

5 2. BACKGROUND & PURPOSE FOR THIS REQUEST FOR INFORMATION 2.1. Background If technical limits of the distribution system will be exceeded and the rectification options are likely to exceed $10M, Ergon Energy is required under the National Electricity Rules (NER) 1 to notify affected Registered Participants 2, AEMO and Interested Parties 3 within the time required for corrective action and meet the following regulatory requirements: Consult with affected Registered Participants, AEMO and Interested Parties regarding possible solutions that may include local generation, demand side management and market network service provider options 4. Demonstrate proper consideration of various scenarios, including reasonable forecasts of electricity demand, efficient operating costs, avoidable costs, costs of ancillary services and the ability of alternative options to satisfy emerging network limitations under these scenarios. Ensure the recommended solution meets reliability requirements while minimising the present value of costs when compared to alternative solutions 5. Ergon Energy is responsible for electricity supply to the South Mackay area (under its Distribution Authority) and has identified emerging limitations in the electricity network supplying South Mackay. The load on Ergon Energy s 11kV supply network has progressively increased such that augmentation is required if reliable supply is to be maintained Purpose of this Request for Information The purpose of this Request for Information is to: Provide information about the existing distribution network in the South Mackay area. Provide information about emerging distribution network limitations and the expected time by which action must be taken to maintain the reliability of the distribution system. Provide information about the criteria that solutions to be provided by parties other than Ergon Energy must meet. Explain the process (including approach and assumptions) to be used to evaluate alternative solutions, including distribution options that are currently being investigated by Ergon Energy. 1 Clause 5.6.2(f) 2 As defined in the NER 3 As defined in the NER 4 NER, clause 5.6.2(f) 5 In accordance with the Australian Energy Regulator s Regulatory Test Version 3, November 2007 Page 4 NA001602T100 Ver 1

6 3. EXISTING SUPPLY SYSTEM TO THE SOUTH MACKAY AREA 3.1. Geographic Region The geographic region covered by this Request for Information is broadly described as the South Mackay area, as shown on the map below. Detailed information on the areas of interest is contained in Section 5.2 and in Appendix A. Figure 1 - South Mackay Distribution Network Highlighting the Proposed Location for Ooralea (OORA) 3.2. Existing Supply System The scope of the study area is bounded by the Pioneer River to the north, the coastline to the east, Rosella Zone Substation to the South and the extent of the West Mackay Zone Substation supply area to the west. The study area includes five existing zone substations and one vacant zone substation site. These are listed below: ALST Alfred Street 33/11kV Zone Substation ROSE Rosella 33/11kV Zone Substation SOMA South Mackay 33/11kV Zone Substation TEST Tennyson Street 33/11kV Zone Substation WEMA West Mackay 33/11kV Zone Substation OORA Ooralea 66/11kV Zone Substation (Proposed). The 2011/12 maximum demand on South Mackay substation was 21.2MVA. Page 5 NA001602T100 Ver 1

7 The South Mackay area has been experiencing significant industrial growth in recent years, with several major industrial connection applications and large areas of proposed residential development. South Mackay Zone Substation (SOMA), which supplies the area, has exceeded its N-1 constraint. In addition, a number of the distribution feeders have become heavily loaded and others are forecast to become heavily loaded within two years. To manage the load at risk during a major contingency event at SOMA, some reconfiguration of the distribution network would transfer loads to an adjoining zone substation, while standby generation is a proposed solution supporting SOMA N-1 until It is proposed to construct a skid-mounted single transformer substation at Ooralea Substation site (OORA) in 2016, to be replaced by a full zone substation at that site in Use of non-network alternatives, such as demand response and demand management, can reduce exposure to risk at those peak times and allow for deferral of network infrastructure. Ergon Energy is releasing a Demand Reduction Incentive Map (DRIM $ per kva) to identify opportunities for small solutions in the South Mackay area which will assign an indicative value to the incentives which Ergon Energy is prepared to automatically pay in a particular area when business rules (as defined in Appendix A) supplied are met. Full details are located on our Ergon Energy Empower website. Overview details are listed at Appendix A to this document in section EMERGING DISTRIBUTION NETWORK LIMITATIONS A load history and forecast for the 2011/12 customer load, is shown in Table 1 below. Table 1: South Mackay Supply Substation Load History and Forecast Year 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 SOMA Substation Load (MVA) N-1 Capacity is: 20.7 MVA It is clear from the load data in Table 1 that:- The loads on South Mackay zone substation have exceeded N-1 capacity of 20.7 MVA during summer 2011/12. In addition:- The load values provided in the table do not reflect the growth for the area, as significant distribution work is also taking place transferring loads to adjoining zone substations to extend the capability for the South Mackay distribution network, before constructing further subtransmission network (Ooralea). Ergon Energy s Security of Supply criteria require that any customer load greater than 5MVA must have N-1 transformer capacity Distribution Feeder Forecast The following distribution feeder load forecasts are based on the network configuration which was in place over the 2011/12 summer period. The growth rates which have been applied to each feeder are based on the growth rates from the 2012 Zone Substation Load Forecast. Note that these particular forecasts do not include the proposed major customer connections and show a general forecast only. Page 6 NA001602T100 Ver 1

8 Table 2 - Ergon Energy's Security of Supply Indicators Table 3: Distribution Feeder Forecast Note: The substation total loads in Table 3 will not match the substation loads in Table 1 as Table 3 are summated feeder loads and a diversity factor needs to be applied. South Mackay Zone Substation experiences a daytime peak following a predominantly industrial and commercial profile during Monday to Friday business operations. The N-1 Capacity of South Mackay Substation is 20.7MVA. This is due to the overcurrent settings to protect the 20MVA transformers cables, with the transformer circuit breakers and transformers having similar limitations. Additional constraints have also been forecast for Rosella and Tennyson Street Zone Substations. Combining these constraints with South Mackay, the following MVA reduction targets have been developed on the basis of no further network injection augmentations being in service before October 2016: Table 4 - Target Peak Load Reductions to Manage Load at Risk Financial Years 2014/ /16 MVA Reduction Targets (Cumulative) 3.65 MVA 4.75 MVA In determining these targets Ergon Energy has assessed the amount of risk it can prudently manage through network switching and load transfer Timeframes for Taking Corrective Action In order to ensure that security of supply to customers in the study area complies with Ergon Energy s planning and security criteria, corrective action should be commenced by summer 2014/15. However the earliest achievable completion date for the first stage of major network augmentation programme is A decision about the selected option is required by June 2014 if any option involving significant construction is to be completed by 2016/ Known Future Network and Generation Development (i.e. projects that have been approved and are firm to proceed) Ergon Energy is not aware of any other network augmentations or continuous running generation developments in the study area that could relieve the emerging network limitations described in section 4.0 above. Page 7 NA001602T100 Ver 1

9 5. INFORMATION ABOUT CRITERIA THAT SOLUTIONS MUST MEET It is important that corrective action be taken prior to summer 2014/15 to maintain a reliable electricity supply to the South Mackay area. This may involve network augmentation or the implementation of local generation or demand side management options which reduce, delay or remove the need for new network investment. This Request for Information, and subsequent consultation, provides an opportunity for alternative solutions to be submitted for consideration. The information provided in this document is intended to enable affected Registered Participants, AEMO and Interested Parties to formulate and propose feasible local generation and demand side management solutions. Ergon Energy has identified the following criteria, to assist solution providers to understand the technical and other requirements. These criteria must be satisfied if solutions are to compensate or rectify the emerging technical limitations of the distribution network. As a distribution network service provider (DNSP), Ergon Energy must comply with technical standards in the NER. In particular, requirements relating to reliability and system security contained in Schedule 5.1 of the NER are relevant to planning for future electricity needs. Amongst other things, Schedule 5.1 requires that: the frequency variations are within the limits described in S5.1.3; voltage fluctuations do not exceed limits set out in S5.1.5; voltage harmonic & notching distortion do not exceed limits set out in S5.1.6; voltage unbalance does not exceed limits set out in S5.1.7; the power system can operate in a stable state as defined in S5.1.8; faults can be cleared in times specified in S5.1.9; load control is in place in accordance with S5.1.10; automatic reclosure requirements are met in accordance with-, S5.1.11; and AEMO be advised of current ratings as required in S AEMO has a related obligation (4.3.1 (f)) to operate the power system within all plant capabilities. Schedule 5.1 also includes details of credible contingencies and levels of redundancy to be considered in planning and operating the distribution network, such as: System Normal : the absolute minimum level of reliability required. Defined as the ability to supply all load with all elements of the electricity system intact (i.e. loss of supply would occur during a single fault or contingency), N-1 : able to meet peak load with the worst single credible fault or contingency, N-2 : able to supply all peak load during a double contingency. Ergon Energy has certain obligations to comply with technical standards under the NER and its Distribution Authority (and subsidiary instruments). These obligations must be taken into consideration when choosing a suitable solution for the South Mackay network technical limitations discussed in this Request for Information. For the South Mackay area, a dynamic solution is proposed. The conventional RFI seeking large solutions ( 5MVA) will be retained, and attended to as normal. The second category covers small solutions that covers demand management permanent reduce demand and demand response. This second category is different in that Ergon Energy has assessed a network value taking into consideration the current preferred network solution and risk. When a proponent, typically a customer provides solutions under the supplied business rules, the proponent is contracted and upon commissioning with measurement and verification, paid the incentive. Page 8 NA001602T100 Ver 1

10 5.1. Large Solution 5MVA Size Timing To meet the security of supply criteria for the South Mackay situation, Ergon Energy needs an additional minimum of 5MVA firm cyclic capacity at 11kV to be provided to this area. This size has been matched to expected load requirements within Ergon Energy s typical 10 year planning horizon or further significant augmentation Location Commissioning needs to be completed by September Additional 11kV capacity is to be delivered to the approximate load centres of the South Mackay Paget and Ooralea area with capability to extend out to other locations where necessary Network Connections Quality Ensure proposed and existing Network Connections have been assessed and detailed in application. Proposed solutions must comply with the relevant standards in the NER and furthermore, must not inhibit Ergon Energy s ability to meet its obligations under the NER and other statutory instruments Reliability Schedule 5.1 of the National Electricity Rules includes details of credible contingencies and levels of redundancy to be considered in planning and operating the distribution network, such as: System Normal : the absolute minimum level of reliability required. Defined as the ability to supply all load with all elements of the electricity system intact (i.e. loss of supply would occur during a single fault or contingency), N-1 : able to meet peak load with the worst single credible fault or contingency N-2 : able to supply all peak load during a double contingency. Ergon Energy s security of supply criteria requires that for a collective of commercial/industrial load of the 5MVA size, N-1 security is required at the 11kV busbars, and 3 into 2 load transfer between 11kV feeders. This level of security implies the parallel operation of critical elements (eg. transformers, generators, circuit breakers) under normal circumstances such that there will be minimal loss of supply during a single contingency event Longevity Options must be capable of providing solutions to the projected limitation in the South Mackay area for a period of at least 10 years. Alternatively solutions must be able to defer additional network investment for a number of years Small Solutions Size a) For customers with energy consumption exceeding circa 100MWh, Permanent Demand Reduction during the Peak Time of Day must be more than 15 kva or 15% of the applicant s maximum demand, whichever is the greater. See Ergon Energy s Empower website and Appendix A located in Section 7.1 on page 15 of this document. b) Refer Ergon Energy s Empower website for a list of Deemed products which Ergon Energy has developed for customers with energy consumption lower than 100MWh. Page 9 NA001602T100 Ver 1

11 5.2.2 Timing c) For Demand Response, the proponent must supply a minimum 250kVA call on generation or call off load detailed on Ergon Energy Empower website and Appendix A located in Section 7.2 on page 16 of this document. d) Solar solutions, battery solutions, and solar/battery solutions with no export restrictions are being considered on a case by case basis for business customers. See Ergon Energy s Empower website and Appendix A located in Section 7 on page 18 of this document. For Small solutions, this will be an open RFI, accepting solutions until such a time as 5MVA of load reductions have been reached or the major network infrastructure is constructed. Each product type listed under section have different business rules with dynamic timings and pricing. The updated contract and pricing regimes will be available at the Empower Website Problem Definition Peak Time of Day Shoulder Times of Day Days of Week Time of Year 10am to 2pm 8am to 10am and 2pm to 5pm Monday to Friday (excluding public holidays) October to the following April Location Additional 11kV capacity is to be delivered to the approximate load centres of the South Mackay area, as defined by the map below: Page 10 NA001602T100 Ver 1

12 Area Designation The target area for Demand Management is all customer sites within the area contained by the designated roads, waterways or landmarks, noted below. The area is also indicated in the map above. The site location is defined by selected NMIs. Peri Rd between Peak Down Highway & Stockroute Rd Stockroute Rd between Peri Rd & Cowleys Rd Cowleys Rd between Stockroute Rd & Bakers Creek Waterway Bakers Creek Waterway between Cowleys Rd & Pacific Ocean East Boundary Rd between Airport Eastern Boundary & Milton St Milton St between East Boundary Rd & Archibald St Archibald St between Milton St & Bruce Highway Peak Down Highway between Broadsound Rd & Peri Rd Network Connections Agreement Altering a connection applies to customers with existing electricity supply. Your connection may need to be altered if you are installing new equipment. Please contact your electrical contractor who will advise if your connection needs to be upgraded. You must meet your network connection agreement obligations to be eligible to apply for the non-network alternate solutions Quality Proposed solutions must comply with the relevant standards in the NER and furthermore, must not inhibit Ergon Energy s ability to meet its obligations under the NER and other statutory instruments. Appendix A to this document and the Empower website have further details on the business rules applicable to the automatic acceptance of small solutions Reliability and Longevity Specific reliability and longevity conditions, such as response time and required run times will be specified in the Demand Reduction Incentive Map, located at Page 11 NA001602T100 Ver 1

13 6. EVALUATION PROCESS 6.1. Evaluation Criteria The Australian Energy Regulator s (AER) Regulatory Test 6 and Chapter 5 7 of the NER mandates the evaluation criteria and requires Ergon Energy to consider demand side management, generation and market network service provider options on an equal footing. The Regulatory Test also specifies the assessment methodology to be used: An option satisfies the regulatory test if: In the event the option is necessitated principally by the inability to meet the service standards linked to the technical requirements of Schedule 5.1 of the NER or in applicable regulatory instruments the option minimises the costs of meeting those requirements, compared with alternative option/s in a majority of reasonable scenarios. 8 An augmentation proposed to meet minimum network performance requirements of Schedule 5.1 of the NER, or other statutory requirements including the Queensland requirements described in Ergon Energy s Distribution Annual Planning Report 9, is referred to as a reliability augmentation. This means that the assessment of solutions will be based on minimising the present value of costs while meeting minimum network performance requirements. A public process is required which includes disclosure of project costs and comparison of alternatives. It is important that all feasible options proposed are considered in the process. If a non-network option satisfies technical requirements, and can be implemented for a lower cost than a distribution augmentation in the required timeframe, it will be necessary for Ergon Energy to enter into a network support agreement with the proponents of the alternative project to ensure supply quality and reliability can be maintained. Since regulated funding (collected via Ergon Energy s network charges) will be required, it is necessary that network support arrangements satisfy the Regulatory Test in terms of both economics and disclosure of relevant costs to the market Submissions from Solution Providers This is not a tender process. Submissions are requested so that Ergon Energy can meet its regulatory obligations to compare the present value cost of alternatives against options of augmenting a distribution supply system to maintain reliability of supply. Ergon Energy will not be legally bound in any way or otherwise obligated to any person who may receive this Request for Information or to any person who may submit a proposal. At no time will Ergon Energy be liable for any costs incurred by a proponent in the assessment of this Request for Information, any site visits, obtainment of further information from Ergon Energy or the preparation by a proponent of a proposal to this Request for Information. Ergon Energy may seek clarification of details from the proponent of a proposed option provided this does not materially alter the proposal. If you propose a solution, it should contain the following information: Details of the party making the submission (or proposing the solution); Details of the party responsible for the providing the solution (if different to the proponent); An explanation of the relevance of the proposal and/or options presented; Technical details of the project (capacity, reliability, availability, proposed connection point if relevant etc) to allow an assessment of the likely impact on supply capability; 6 AER s Regulatory Test Version 3, November Clause (f) and (g) 8 Emphasis added by Ergon Energy 9 Ergon Energy s Network Management plan is available on its website - Page 12 NA001602T100 Ver 1

14 If applicable to the solution being offered: - the size, type and location of load(s) that can be reduced, shifted, substituted or interrupted - the size, type and location of generators that can be installed or utilised if required; - the type and location of action or technology proposed to reduce peak demand/provide electricity system support; Sufficient information to allow the costs of the solution to be incorporated in a cost effectiveness comparison in accordance with AER s Regulatory Test; Information about the impact on the proposal if electricity demand were to be 25% above/below Ergon Energy s forecasts. An assessment of the ability of the proposed solution to meet the technical requirements of the NER; Timing for availability of the option, and whether it is a committed project 10 ; The level of payment required to fund the proposal (initial payment, availability payment, dispatch payment etc) in both $s and/or $/kva; Other material that would be relevant in the assessment of the proposed solution. Submissions to this Request for Information will need to be described in the consultation process and will be made public. As such, any commercially sensitive material, or material that the party making the submission does not want to be made public, should be clearly identified. It should be noted that Ergon Energy is required to publish the outcomes of the Regulatory Test analysis. If solution providers elect not to provide specific project cost data for commercial-inconfidence reasons, Ergon Energy may rely on cost estimates from independent specialist sources Public Consultation Part A Large Scale Solutions > 5MVA Ergon Energy actively encourages providers of large non-network solutions to respond to this Project Proposal and Public Consultation with detailed proposals for initiatives that can provide more than 5MVA towards meeting these targets. Proposals will be accepted and assessed as per Sections 6.1and 6.2 above. Part B Small Solutions Ergon Energy actively encourages providers of small non-network solutions to respond to this Project Proposal and Public Consultation by visiting the Ergon Energy Empower website and take up a demand management opportunity within one or more of the categories. Ergon Energy has recently advertised and actively promoted a trade ally network for the Mackay area to assist customers achieve the demand management opportunities. Ergon Energy personally invited the large customers with energy consumption greater than circa 100MWh and trade ally network members to attend a briefing on the DRIM, held in Mackay on 10 October 7 am. Ergon Energy sought formal registrations of interest. Subsequent proposals received will be evaluated and where a proposal represents a viable solution at an acceptable cost, the proponent will be contacted. Members of the public and other interested parties are also encouraged to comment on the proposed project. Contact information can be found in section 1 Introduction on Page 3 of this document Demand Reduction Incentive Map (DRIM) Ergon Energy encloses a DRIM for the South Mackay area (Appendix A). The DRIM shows the demand map and contract for South Mackay and Rosella. The DRIM indicates the level of incentives that Ergon Energy is prepared to pay for demand management and demand reduction schemes in the study area (up to a total of 5MVA). 10 As defined in the AER s Regulatory Test Page 13 NA001602T100 Ver 1

15 The DRIM will be reviewed and updated on a regular basis, with the indicative values of the incentives fluctuating in accordance with both the take up of initiatives and network requirements. It is anticipated that this new form of market engagement will open up demand side participation opportunities to a wider range of customers. If proponents wish to be updated with the South Mackay DRIM incentive values over the period of the proposed to 2016, please register your interest by becoming a member of Ergon Energy s Trade Ally Network or periodically visit the Empower website. To find out more information about Trade Ally Network membership, please TradeAllyNetwork@ergon.com.au Timetable for Submissions Submissions in writing (preferably electronic format) are due by 23 December 2013 and should be lodged to: Attention: Network Planning and Strategy regulatory.tests@ergon.com.au 6.6. Assessment and Decision Timetable Ergon Energy intends to carry out the following process to assess what action should be taken to address the identified distribution network limitations: Step 1 Request for (initial) Information (i.e. this Request for Information). Date Released: 28/10/2013 Step 2 Submissions in response to the Request for Information. Due Date: 23/12/2013 Step 3 Step 4 Review and analysis by Ergon Energy. This is likely to involve further consultation with proponents and additional data may be requested. Release of Ergon Energy s Consultation Paper and Draft Recommendation of solution which satisfies the Regulatory Test. Anticipated to be completed by: 13/01/2014 Anticipated to be released by: 28/01/2014 Step 5 Submissions in response to the Consultation Paper & Draft Recommendation. Due Date: 25/02/2014 Step 6 Release of Final Recommendation (including summary of submissions received). Anticipated to be released by: 11/03/2014 Ergon Energy reserves the right to revise this timetable at any time. The revised timetable will be made available on the Ergon Energy website. Ergon Energy will use its reasonable endeavours to maintain the consultation program listed above. However this program may alter due to changing power system conditions or other circumstances beyond the control of Ergon Energy. Updated information will be made available on our website: The consultation timetable is driven by the need to make a decision by 11 March 2014 if any option involving significant construction is to be in place by September At the conclusion of the consultation process, Ergon Energy intends to take steps to progress the recommended solution to ensure system reliability is maintained. Page 14 NA001602T100 Ver 1

16 7. APPENDIX A Area designation: The target area for Demand Reduction is all customer sites within the area contained by the designated roads, waterways or landmarks noted below. Peri Rd between Peak Down Highway & Stockroute Rd Stockroute Rd between Peri Rd & Cowleys Rd Cowleys Rd between Stockroute Rd & Bakers Creek Waterway Bakers Creek Waterway between Cowleys Rd & Pacific Ocean East Boundary Rd between Airport Eastern Boundary & Milton St Milton St between East Boundary Rd & Archibald St Archibald St between Milton St & Bruce Highway Peak Down Highway between Broadsound Rd & Peri Rd 7.1. Permanent Demand Reduction Problem Definition: Peak Time of Day Shoulder Time of Day Days of Week Time of Year Area Demand Reduction Target 10am to 2pm 8am to 10am and 2pm to 5pm Monday to Friday (excluding public holidays) October, to the following April 1.5MVA (subject to regular review) Page 15 NA001602T100 Ver 1

17 7.1.2 Demand Reduction Incentive $300/kVA An additional Incentive of $100/kVA will apply if Demand Reduction is installed and commissioned by 1 September Once the Area Demand Reduction Target (currently 1.5 MVA) has been achieved in aggregate, reduced Incentives will apply Contract Successful applicants will be required to enter into a Permanent Demand Reduction contract based on the following concepts: Applicant must be: o Owner or lessee of the nominated premises, or o The current electricity account owner for the nominated premises. Demand Reduction during the Peak Time of Day must be the greater of 15 kva or 15% of the applicant s maximum demand. Permanent Demand Reduction will be achieved by a fixed date and in an identified manner which may be, but not limited to, any of the following: o permanent installation of energy efficient equipment, lighting, air conditioning etc o permanent change of energy source (e.g. electricity to gas) o permanent change of times of operation to reduce the applicant s maximum demand at Peak Time of Day o permanent improvement of power factor beyond statutory limits Permanent Demand Reduction Incentive payment will equal the Demand Reduction Incentive value multiplied by the actual verified Demand Reduction across the Peak Time of Day. Permanent Demand Reductions must be kept in place for at least an agreed period or else the Incentive payment will be required to be refunded on a pro-rata basis Call-On Generation and Call-Off Load Problem Definition: Peak Time of Day 10am to 2pm Shoulder Time of Day 8am to 10am and 2pm to 5pm Days of Week Monday to Friday (excluding public holidays) Time of Year October to the following April Duration required 1 October 2014 to 30 April 2016 Area Demand Response Reduction 1.0MVA (subject to regular review) Target Demand Reduction Incentive $80/kVA/annum plus an agreed running or call-off $/hour, when notified Once the Area Demand Response Reduction Target (currently 1.0 MVA) has been contracted in aggregate, reduced Incentives will apply Contract Successful applicants will be required to enter into a Demand Reduction contract based on the following concepts: Page 16 NA001602T100 Ver 1

18 General Applicant must be 1. The owner or lessee of the nominated premises, 2. The current electricity account owner for the nominated premises, or 3. A proponent with a signed agreement with 1 or 2 above. The fixed monthly payments will equal the nominated Demand Reduction Incentive value multiplied by the actual verified Demand Reduction. In addition, there will be an agreed running or call-off payment per hour, if notified by Ergon Energy during the month. The monthly Demand Reduction Incentive payment will be reduced if the Demand Reduction is not provided, as and when required. Call-on Generation The plant must be ready to operate by a specified date. A pre-agreed deposit amount will be forfeited by the applicant if the plant is not available by that date. The plant must be able to provide a specified Demand Reduction (which must be more than 250kVA) during the Peak Time of Day. The minimum and maximum running hours for a Demand Reduction event shall be specified. A maximum number of plant running hours per annum shall be specified. The plant must provide the Demand Reduction within a specified response time, at any time within the specified periods when notified by Ergon Energy. Call-off Load > 250kVA The applicant must be able to reduce its load to a specified level which is at least 250 kva lower than its normal maximum demand at the Peak Time of Day. The minimum and maximum Call-off Load durations shall be specified. A maximum number of Call-off Load hours per annum shall be specified. The applicant must provide the Call-off Load Demand Reduction within a specified response time at any time within the specified periods when notified by Ergon Energy. Call-off Load >50kVA within 2 minutes The applicant must be able to reduce its load to a specified level which is at least 50kVA lower than its normal maximum demand at the Peak Time of Day within 2 minutes of being notified by Ergon Energy. The minimum and maximum Call-off Load durations shall be specified. A maximum number of Call-off Load hours per annum shall be specified. The applicant must provide the Call-off Load Demand Reduction within the 2 minute response time at any time within the specified periods when notified by Ergon Energy. The Call-off Load requirement may be notified and automatically controlled via building management system, PLC or similar The Call-off Load Demand Reduction could be managed across a number of sites by an aggregator. Page 17 NA001602T100 Ver 1