Management of Embedded Technologies

Transcription

1 Management of Embedded Technologies

2 Version Date Change March 2015 First Draft April 2015 Second Draft IMPORTANT Disclaimer The information in this document is provided in good-faith and represents the opinion of Transpower New Zealand Limited, as the System Operator, at the date of publication. Transpower New Zealand Limited does not make any representations, warranties or undertakings either express or implied, about the accuracy or the completeness of the information provided. The act of making the information available does not constitute any representation, warranty or undertaking, either express or implied. This document does not, and is not intended to; create any legal obligation or duty on Transpower New Zealand Limited. To the extent permitted by law, no liability (whether in negligence or other tort, by contract, under statute or in equity) is accepted by Transpower New Zealand Limited by reason of, or in connection with, any statement made in this document or by any actual or purported reliance on it by any party. Transpower New Zealand Limited reserves all rights, in its absolute discretion, to alter any of the information provided in this document. Copyright The concepts and information contained in this document are the property of Transpower New Zealand Limited. Reproduction of this document in whole or in part without the written permission of Transpower New Zealand is prohibited. Contact Details Address: Transpower New Zealand Ltd 96 The Terrace PO Box 1021 Wellington New Zealand Telephone: Fax: system.operator@transpower.co.nz Website:

3 Purpose... 4 Introduction... 5 Background... 6 National Grid Frequency Deviation and Automatic Demand Disconnection, 27 May GB Industry Structure Relevant to the Events of 27 May National Grid s Role as GB System Operator (GBSO): Frequency Control and System Operating Margin... 6 Generators... 7 Distribution Network Operators... 7 NZ Industry Structure Relevant to Similar Events Today... 7 Transpower s Role as System Operator (SO): Principal Performance Obligations and Security of Supply Policy... 7 Generators... 8 HVDC owner... 9 Distributors... 9 Purchasers... 9 Risks to the NZ power system from embedded disruptive technologies Ability for the New Zealand framework to monitor and manage National Grid Event New Zealand New Zealand Experience Consequence of possible events Operability Frameworks National Grid: Future Electricity Scenarios & System Operability Framework UK RoCoF Regime for Distributed Generation Transpower: Annual Planning Report & System Security Forecast Need for change to existing frameworks Access to information Extended Reserves (AUFLS) Conclusion: Need For Ongoing Operational awareness

4 PURPOSE This paper explores whether, from an overall integrated power system at the system level, the structure of the New Zealand electricity industry is expected to support the prudent management of risks that may arise from the adoption of smart grid technologies. 4

5 INTRODUCTION The attention of Smart Grid Forum (SGF) members was drawn to the potential impact a large number of relatively small generation units, if not factored into power system security analysis, could have on overall power system stability and integrity. In his presentation to the Forum in February, John Scott, Director Chiltern Power, outlined two examples: the impact embedded generation had on UK power system during an underfrequency event in May ; and the changing reactive / active power ratio of Britain s load. While the latter is still under investigation in the UK John Scott considered the structural issues raised by both examples to be similar. 5 Subsequent discussion indicated that SFG members would like to know: how similar themes around risks to overall power system integrity due to distribution-embedded disruptive technologies would manifest themselves in New Zealand; likely consequences of such events; how existing institutions would monitor and control them; who would be accountable for mitigating them; what organisational support that entity would have; what authority would go with that accountability; and whether it would be adequate and effective. The following sections summarise salient points from the UK under-frequency event and prevailing GB and NZ industry structures, discusses issues raised by members about the NZ context, and identifies issues that we need to remain aware of as smart grid technologies are integrated into today s power system. 1 See pages of industries/energy/electricity/new- zealand- smart- grid- forum/meeting- 5/workstream- d- report- governance.pdf

6 BACKGROUND NATIONAL GRID FREQUENCY DEVIATION AND AUTOMATIC DEMAND DISCONNECTION, 27 MAY On 27 May 2008 the near simultaneous loss of four generators generating units totalling 1714MW resulted in a drop in system frequency to 49.15Hz. The frequency oscillated around this level for about 1.5 minute then fell to 49Hz when a further sharper drop to Hz occurred triggering the operation of automatic low frequency relays and the disconnection of 546MW of demand. The low frequency disconnection scheme operated as expected and the efficiency of the scheme did not come into question. Data from Distribution Network Operators (DNOs) indicated that during the frequency fall from 49.15Hz 279MW of embedded generation tripped 2. This event was the third incidence of frequency falling below 49.5Hz for 60 seconds since 1989/90 and the first operation of the National Low Frequency Demand Disconnection (LFDD) scheme since GB INDUSTRY STRUCTURE RELEVANT TO THE EVENTS OF 27 MAY 2008 The following outline of the GB industry structure is based on National Grid s description 3 of the industry framework relevant to the 27 May event and very limited review of the national Grid Code. National Grid, as GBSO, is responsible for the management of transmission network security and real time balancing of generation with demand. Any imbalance between generation and demand will result in frequency perturbations. National Grid manages the system frequency to the defined statutory limits of ±0.5Hz and operational limits of ± 0.2Hz. The GB Security and Quality of Supply Standard (GB SQSS) specifies the limit of frequency deviations for secured faults, which includes loss of a single generating unit or DC bi-pole as being: Normal Infeed Lost Risk (1000MW): Maximum deviation should not exceed 0.5Hz; and Infrequent Infeed Lost Risk (1320MW): Frequency should not deviate outside the range 49.5Hz to 50.5Hz for more than 60 seconds. The largest Infrequent Infeed Lost Risk is derived from the largest possible generation infeed loss on the transmission system that will result from a single secured event. For a generation losses larger than the Infrequent Infeed Lost Risk or a large generation deficit in an importing power island following a system split, the National Low Frequency Demand Disconnection (LFDD) scheme automatically disconnects demand. The LFDD 2 www2.nationalgrid.com/assets/0/745/746/3464/3466/3488/3475/745fc2ac-d57e-4df7-b619-4c68f2821e8d.pdf 3 www2.nationalgrid.com/assets/0/745/746/3464/3466/3488/3475/745fc2ac-d57e-4df7-b619-4c68f2821e8d.pdf

7 scheme facilitates the disconnection of 60% of load connected to the National Grid Transmission Area in nine blocks with trip frequencies ranging from 48.8Hz to 47.8Hz, and 40% of load connected to the Scottish Transmission Area (including Scottish Hydro) in six blocks with trip frequencies ranging from 48.6Hz to 48.0Hz. All transmission connected generation, and all registered (DNO connected) capacity of generation in: England and Wales >=50MW; Scottish Power Transmission Ltd region >=30MW; and Scottish Hydro- Electric Transmission Ltd region >=10MW, must maintain stable operation in the range 47.5Hz to 52Hz, and be able to operate for at least 20 seconds in the range 47Hz to 47.5Hz. 7 At the time, there was an expectation that all DNO connected, embedded generation below these values met the Engineering Recommendations (G75 or G59) to support stable operation in the range 47 or 48Hz to 52Hz, although the Recommendations were not mandatory. DNOs are required to maintain the requisite LFDD capability and procedures to implement manual demand control on instruction from the GBSO. NZ INDUSTRY STRUCTURE RELEVANT TO SIMILAR EVENTS TODAY The Electricity Industry Participation Code 2010 (Code), made and administered by the Electricity Authority (Authority) 4, specifies the Principal Performance Obligations (PPOs) of the SO. These obligations require the SO, as a reasonable and prudent operator 5, to: dispatch available assets (generation, transmission, demand, and ancillary services) in a manner that avoids cascade failure of assets resulting in the loss of demand; and but for momentary fluctuations, seek to maintain the frequency within the normal band (49.8Hz 50.2Hz). Frequency fluctuations should remain within 47Hz 52Hz and the incidence of fluctuations should not exceed specified quanta, the larger the quantum the less frequent the incidence, e.g. the incidence of frequency falling below 48Hz should not be more frequent than the statistical equivalent of once every five years. 4 In fulfilling this role the Authority may seek independent advice from the Security and Reliability Council (SRC) on the performance of the electricity system and reliability of supply issues. The SRC does not have the authority to commission analysis or to commit resources [but] may recommend resources, external to the Authority, the SRC considers to be necessary to perform its function. 5 Refer to the Code for a definition of this term

8 In its Policy Statement the SO sets out the policies and procedures it will employ to meet the PPOs and manage grid emergencies. One policy, the Security Policy 6, identifies the range of events (e.g. the loss of generation, the loss of one or both poles of the HVDC link) that may cause frequency deviations from the normal band. These events are classified into one of two categories: 8 contingent events, for which the impact and probability justify the procurement of ancillary services (principally instantaneous reserves) or the application of constraints in the scheduling and dispatch processes to maintain frequency above 48.0Hz and avoid demand shedding; and extended contingent events, for which the impact and probability do not justify the avoidance of demand shedding. Adequate instantaneous reserve is procured so that, in concert with automatic under-frequency load shedding (AUFLS) and the application of constraints in the scheduling and dispatch processes, frequency remains above 47Hz in the North Island and 45Hz in the South Island. For extended contingent events (e.g. the simultaneous loss of two large generating units, the loss of both poles of the HVDC link at times of high transfer) it is anticipated that the AUFLS scheme automatically disconnects demand. The AUFLS scheme facilitates the disconnection of 32% of either load directly connected to the grid 7 or distributor connected load in two blocks 8 with trip frequencies ranging between 47.8Hz and 47.5Hz in the North Island and between 47.5Hz and 45.5Hz in the South Island. In assessing the performance of the power system the SO may rely on asset owners meeting performance obligations specified in the Code and may seek any additional information it reasonably requires from asset owners to assist it in such assessments. In essence, through the requirement on generators (refer below) to notify their intent to connect or application to connect, the SO is able to learn of the existence of generation and, to meet its PPOs, the SO must identify and gather the information it requires to conduct the necessary analysis required to enable it to meet its obligations. Each generating station in excess of 30MW (or less if directed by the Authority), connected to either the grid or a local network must ensure its assets remain connected and makes the maximum possible contribution to maintaining frequency within the normal band or restore frequency to the normal band while the frequency in the North Island remains above 47.5Hz 9. For NI frequencies between 47.5Hz and 47Hz NI generators must remain connected for, declining, specified periods. In the SI generators must remain connected while the frequency remains above 47Hz and for 30 seconds if the frequency falls below 47Hz but remains above 45Hz. 6 The SO must adopt policies that are consistent with the Authority s objective to promote reliable supply by, and the efficient operation of, the electricity industry for the long-term benefit of consumers. In this policy the key trade-off is the cost of procuring instantaneous reserve and constraining generation, and the expected cost of lost load should an under-frequency event occur. 7 Many grid connected loads hold dispensations from this obligation. 8 The Authority and SO currently have a project underway that will split this obligation across four blocks. 9 Unlike the UK in 2008, there is no requirement for generation connected to local networks to install rate of change of frequency relays this would be at odds with contributing to the maintenance of frequency.

9 A generator who is planning to connect a unit of 1MW or greater must advise the SO of the intent to connect. Anyone wishing to connect generation, however small, to a local network must apply to the Distributor for connection. The HVDC owner must make the maximum possible contribution to maintaining frequency within the normal band or restore frequency to the normal band while frequency in both islands remains above 48Hz. For frequencies between 48Hz and 45Hz the HVDC must remain connected for, declining, specified periods. Distributors are required to maintain the AUFLS (or shortly, Extended Reserve) capability and procedures to implement manual demand control on instruction from the SO. 9 Distributors are required to provide information about connected load and generation reasonably requested by the SO. As new technologies emerge it is anticipated that related information will be requested on an ad hoc basis before forming part of asset capability statements. Purchasers must limit the magnitude of any instantaneous change in offtake to the levels reasonably required by the SO in light of its obligation to meet its PPOs.

10 RISKS TO THE NZ POWER SYSTEM FROM EMBEDDED DISRUPTIVE TECHNOLOGIES Forum member question(s) how similar themes around risks to overall power system integrity due to distribution-embedded disruptive technologies would manifest themselves in New Zealand? 10 The loss of embedded generation during the UK event does not seem to have been anticipated and has brought into question the lack of explicit frequency performance criteria for small embedded generation. The under-frequency performance of small embedded generation is but one of a number of risks that may arise from the integration of smart grid technologies into the NZ power system, others include: electric vehicles; the rate of change and quantum of demand at common charging times not reflected in prices observed by vehicle owners; and poor coordination of injection from storage; concentrated areas of embedded generation (e.g. PV, micro wind) may introduce distribution voltage management challenges; and ultimately complexity in the management of GXP voltages; wide scale utilisation energy management systems in homes and commercial premise s leading to a coincident demand response; and impact of distributed generation and demand response on provision of AUFLS (extended reserves) The above list is unlikely to be exhaustive however the method of frequency management, discussed below, is largely generic. If the expected incidence of underfrequency events increases different management practices may be more economic. With the possible exception of events more extreme than anticipated, power system security ought not to be threatened by unidentified risks.

11 ABILITY FOR THE NEW ZEALAND FRAMEWORK TO MONITOR AND MANAGE Forum member question(s): how existing institutions would monitor and control them? who would be accountable for mitigating them? NATIONAL GRID EVENT From the description provided by John Scott and that set out in the National Grid report it is not apparent the extent to which National Grid had to take account of the quantum or under-frequency performance of generation embedded within distribution networks. Or, whether in drafting the obligation on National Grid to balance generation with demand in real time did the authors assumed the level of embedded generation would be minimal, or embedded generation would comply with the prevailing Engineering Recommendations? 11 The National Grid report makes no comment on how it is expected to become aware of embedded generation or its capability. Requirement or comment on the need for small scale generation to apply to or notify DNOs of their existence has not been sighted. Similarly the requirement for DNOs to pass information about distributed generation to the GBSO, or for the GBSO to seek such information has not been sighted. At the end of the day the National Grid report concluded: based on simulation, the loss of grid connected generation, was sufficient in themselves to cause frequency to fall below 48.8Hz and initiate the LFDD scheme; and the LFDD scheme protected the overall system from exceptional generation loss as designed and prevented a wide scale shutdown. NEW ZEALAND The electricity industry (commonly considered, but not limited to: generation, transmission, distribution, and retail) is governed by the Authority who must promote reliable supply, and efficient operation, for the long-term benefit of consumers by, amongst other functions, administering the Code. In short the Authority is accountable for defining accountability and ensuring the industry participants (generators, grid owners, distributors, retailers, and service providers 10 have, or are able to obtain, the information and with, in some instances the Commerce Commission, resource to deliver required outcomes (adequate reward through market, regulatory, or service provider contract for cost of delivery). In respect of the reliable operation of the industry the Code: 10 Appointed by the Authority to fulfil the roles prescribed in the Code. The SO is one such service provider.

12 places asset performance obligations on generators, the grid owner, and distributors (asset owners); specifies system performance obligations (including the PPOs), to be attained by the system operator through acquiring asset owner information, analysis, and the scheduling and security constrained dispatch processes; and places an obligation on asset owners to provide information reasonably requested by the system operator. The system operator may rely on asset owners attaining their performance obligations but must also identify and gather the information required to schedule and dispatch assets, including load, in a manner that manages frequency and avoids cascade failure. 12 To assist the SO manage frequency the Code also: requires every generator who plans to connect a new generating unit in excess of 1MW to the grid or local network must advise the SO accordingly; requires all distributed generation to apply for connection to distributors. Applications must contain information required by distributors; provides for the SO to make reasonable requests of distributors for information about demand profiles, and frequency characteristics of demand and distributed generation; and enables the SO, if it is sufficiently concerned about the under-frequency performance of generation, to manage the consequent risk through the procurement of additional instantaneous reserves. The SO monitors and analyses information about frequency response characteristics of generation and demand obtained through asset owner asset capability statements, ad hoc requests and test results (commissioning and re-commissioning, routine, and post event). The SO also conducts post event analysis of asset and ancillary service provider performance from monitoring data collected by asset owners (SCADA, event recorders, phasor measurement units, metering). A recent example is the apparent under performance of an interruptible load provider has revealed the limited under-frequency performance of multiple sub 1MW generating units. The Code does not restrict the initiatives the SO can purse to improve the means it uses to meet its obligations. In fact the Code requires the SO to be a reasonable and prudent operator who employs good international practice. To this end, within the last three years, the SO: has conducted an extensive technical of the existing AUFLS regime 11 and an economic review alternate means of scheme options 12 ; has recommended New Zealand move from a two block AUFLS regime to a four block regime to reduce the impact of under-frequency load shedding during some events and improve the quality of frequency management 13 ; The Authority has extended this initiative to refine the selection of load to be shed during under-frequency events.

13 has upgraded the reserve management tool used in its scheduling and dispatch processes; is utilising the real-time digital simulator acquired by Transpower to design and commission Pole 3 and the new HVDC control system to augment its transient stability analysis; and begun to use phasor measurements and high resolution event data to understand the aggregate response of generation embedded within networks. In sum, the SO is responsible for achieving the frequency performance obligations set by the Authority. To achieve this outcome the SO is dependent on the receipt of quality information. To date, with few exceptions, quality information has been available to the SO. In respect of small scale distributed generation (sub 1 MW) it is expected distributors, or the Market Administrator, through the registration process will obtain the number, location, and connected capacities. While the Code provides for these channels to be a conduit for obtaining information about the technical capability of such generation it may be more pragmatic for the SO to obtain such information from suppliers or test the performance of such equipment itself. 13 NEW ZEALAND EXPERIENCE Compared to electricity systems in other first world countries New Zealand s power system, with a peak load of 7000MW, is small. In % of generation was from renewable resources: hydro, geothermal, and wind. Today there are only four fossil fuelled generating units in excess of 200MW in regular use. Consequently, by international comparison, the inertia of the power system is low and frequency deviations greater, under-frequency load shedding doesn t begin to occur until 47.8Hz in New Zealand. Successful management of frequency during contingent events is critical to the secure operation of the power system. Since the adoption of the frequency management policy described above in 2004 the AUFLS scheme has operated twice, on: 13 December , when 874 MW of generation was lost at Huntly. North Island frequency fell to Hz and block 1 of NI AUFLS and IL operated 15, shedding 564MW. Frequency returned to the normal range within about 14 seconds. The majority of load shed was restored within two and a half hours; and 12 November , 835 MW was lost in the North Island when there was an unanticipated HVDC ran back from 975 MW to 140 MW during a commissioning test. AUFLS and IL interrupted 606 MW of load. Frequency returned to the normal range within about 33 seconds. Comment from John Scott suggests surprise at New Zealand s tolerance for underfrequency load shedding events. As foot noted above the policy that gives rise the utilisation of under-frequency events is based on a trade-off between short term market costs (procurement of instantaneous reserves, constraints on generation (to manage the quantum of risks), and the co-optimisation of energy and reserve procurement in the scheduling process) and the expected cost of lost load arising from under-frequency load Metering does not allow AUFLS and IL to be identified separately. 16

14 shedding a function of the cost of non-supply and expected incidence. The rationale for the equivalent UK policy has not been explored. Within the New Zealand context it would seem that such an exercise would only be warranted if the Authority s objective was under review. 14

15 CONSEQUENCE OF POSSIBLE EVENTS Forum member questions(s): likely consequences of such events? The consequence of unanticipated events is a not entirely predictable. Asset owners are expected to maintain protection systems that isolate their equipment from outcomes that exceed specified voltage, frequency, and overload capabilities. The final event management measure is the disconnection of demand to maintain a balance with available supply. 15 The addition of new generation is observable, albeit with shorter and shorter lead times, and new risks should be identifiable. The addition of new demand should be observable within a timeframe that allows associated risks to be managed. The rapid adoption of demand management technologies may create some uncertainty. It is likely that such technologies will be facilitated through web or mobile communication networks. Events within these networks may have consequential impacts on electricity demand.

16 OPERABILITY FRAMEWORKS Forum member question(s): map UK system operability framework against NZ documents. NATIONAL GRID: FUTURE ELECTRICITY SCENARIOS & SYSTEM OPERABILITY FRAMEWORK 16 National Grid has developed a number of scenarios in response to possible domestic and international economic, energy, and climate change policy, described in the Future Electricity Scenarios 17 (FES). In its System Operability Framework 18 (SOF) National Grid aims to outline how it expects future system operability to change in response to the developments described in an endeavour to help existing and future customers identify new and enhanced service opportunities on its transmission systems out to National Grid expects to publish the FES annually with the aim of projecting future energy landscapes, in terms of demand, generation, and to identify the need for additional transmission capacity. The SOF, also expected to be an annual publication, is designed to study the scenarios described in FES from a system operability perspective, taking into account current system operation experience. It is expected to highlight the key operability variances under each of the scenarios set out in FES to provide an assurance that the risks associated with operability are identified. This is to ensure that the necessary mitigating measures can be evaluated early enough to allow for full economic assessment and timely implementation of solutions. Most distributor connected generation in the UK utilises a rate of change of frequency (RoCoF) protection regime to detect when the distribution system to which is connected has been isolated from the National Grid. As the UK invests in low inertia, renewable, generation frequency deviations arising from the loss of large generation units have the potential to activate distributor connected generation RoCoF protection regimes exacerbating the management of frequency. New Zealand does not face this issue as we do not utilise RoCoF protection to detect the islanding of distributed generation. TRANSPOWER: ANNUAL PLANNING REPORT & SYSTEM SECURITY FORECAST Transpower preparers and publishes an Annual Planning Report (APR) 19 that provides information about: the capabilities of the existing grid; The latest annual plan may be found on the Transpower website

17 demand and generation forecasts for up to 15 years; the grid s ability to meet future demand and generation needs; the role of the transmission grid in facilitating generation; grid investment that may be required to meet future needs for up to 15 years and beyond, by way of: o o grid backbone transmission plans for the main North and South Island transmission corridors, and for the HVDC link; and 13 regional plans; and a 10- year forecast of fault levels at each Transpower s transmission bus. Every second year the ARP includes: a Grid Reliability Report (GRR) 20, which sets out 10- year forecasts of demand at grid exit points and generation at grid injection points, and whether the National Grid can be reasonably expected to meet (n- 1) security requirements; and 17 a Grid Economic Investment Report (GEIR) 21, which identifies economic investments (creates net market benefits) that Transpower considers could be made in respect of the interconnection assets. In accord with the Code Transpower, as the SO, prepares a System Security Forecast (SSF) 22 every two years and updates six monthly in the intervening period. The SSF provides information about: the SO s ability to meet the principal performance obligations (PPOs) over the ensuing three period, which may be extended to up to five years or more to elaborate on areas of the network which may require the utilisation of operational constraints. The forecast takes into account the capabilities of the grid and connected assets based on information known to, and able to be disclosed by, the System Operator; and to identify and describe potential power system issues which may require operational management over the next three years or more to enable the System Operator to meet the PPOs prior to investment in upgrades and investment in transmission alternatives. 20 Requirement of Part 12 of the Code 21 Requirement of Part 12 of the Code 22 The latest System Security Forecast may be found on the Transpower website

18 NEED FOR CHANGE TO EXISTING FRAMEWORKS Forum member question(s): what organisational support that entity would have; what authority would go with that accountability; and whether it would be adequate and effective. 18 The SO has not identified any need for change to primary authority or accountabilities. Two areas in which refinement may be required are access to information about new technologies and refinement to the design of the extended reserves regime. Need for change has yet to be demonstrated. Each is discussed by way of example. ACCESS TO INFORMATION To date the requirement for the SO to be notified of new generation units in excess of 1 MW has created adequate opportunity for the SO to seek information from EDBs about those aspects of the new generation that will impact system management, principally those related to frequency characteristics. The SO doesn t have, nor is it resourced to have, an immediate relationship with smaller consumers. Most new technologies will be adopted by smaller consumers. The Code anticipates that the SO will seek information about small scale distributed generation (DG) and demand from EDBs. Until the emergence of wind and solar generation there has been little change in DG technologies. Historically DG has been owned by EDBs or the owners of manufacturing processes. These owners are usually familiar with the technical capability of the DG they own and operate. The transaction cost of obtaining information about such generation has usually been low for both EDBs and the SO. Demand has largely been passive, or managed by EDBs with the likes of ripple control. Again EDBs have been the natural source of information on such capabilities. It is anticipated that new DG, new demand (e.g. EVs), and new demand management capability will be acquired from multiple suppliers by multiple consumers. Obtaining information on these technologies, their uptake, and location in accord with the Code may impose higher transaction costs on EDBs. The SO expects to work with EDBs, and if needed the Authority, to ensure information required for security analysis is obtained cost effectively. EXTENDED RESERVES (AUFLS) The Authority is working towards the implementation of the Extended Reserves regime which will replace the t AUFLS regime. Under the AUFLS regime EDBs are responsible ensuring minimum quantities of load are armed for interruption. In order to select EDB feeders armed for interruption on a more efficient basis EDBs will be required to provide information about the nature of feeder loads to a central selection process. The regime anticipates that the primary selection of feeders armed for interruption will be made once every five years with an annual revision based on updated information.

19 The adoption of new technologies by consumers could materially change the nature of load connected to a feeder within a 12 month period. This may necessitate more frequent provision of information, from EDBs, and review of selected feeders. 19

20 CONCLUSION: NEED FOR ONGOING OPERATIONAL AWARENESS The current framework for monitoring the addition of new generation and obtaining the necessary information is adequate. 20 While new technologies and the rate at which they are adopted is expected to increase the complexity of power system operation for EDB operators and the SO, at least in transition, has not identified any need for change to primary authority, roles, or accountabilities. To meet its obligations the SO anticipates there will be greater and more frequent exchange of information between participants. A first pass suggests the following areas and primary stakeholders: uptake of demand response and response capability (SO, EDBs); ongoing currency with frequency and fault capability of small scale DG installed in NZ (SO, EDBs); ongoing EV uptake and capability, as previously outlined (EDBs, SO, GO); voltage management within distribution networks (EDBs); impact of distribution network voltage management on GXP voltage management (EDBs, GO, SO); integrity of protection systems with proliferation of small scale DG (EDBs, GO, SO); and uptake of stationary storage and utilisation (SO, EDBs). The SO does not underestimate the work that may be required to identify, build, and operate the systems necessary to facilitate information exchanges required to support a competitive market, and the ongoing reliable and efficient operation of the power system. The SO expects to work closely with relevant stakeholders, including the Authority, to facilitate the necessary outcomes.