Christchurch Stakeholder Forum. Christchurch 11 th July 2011

Transcription

1 Christchurch Stakeholder Forum Christchurch 11 th July 2011

2 Transpower = The National Grid We Plan, Build, and Maintain your grid, and, Operate your electricity system in real time.

3 Your National Grid 11,800 km of high voltage lines; 181 substations. 41,000 towers and poles. 1,000 power transformers; 2,300 circuit breakers. Our assets are located in all 85 Regional, District and City Councils

4 24 x 7 operation. Real-time operations Two System Operations Control Centres running as a single virtual centre. Three Regional Operating Centres (switching centres)

5 Why we are here today Creating a robust and enduring grid requires significant ongoing investment. Making the right investments at the right time requires good planning. This requires greater consultation, integration and collaboration with our Stakeholders. We need to better understand the future needs of end consumers. We want to discuss, and seek input, on current Grid issues, our initiatives to resolve - and start an ongoing dialogue with you on the future development of your National Grid.

6 length of transmission lines built (km) electricity generation (GWh) mid-decade Our Challenge Average age of the grid 3,500 50,000 3,000 2,500 2,000 1,500 1, s 1930s 1940s 1950s 1960s 1970s 1980s 1990s since 2000 length built Demand 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0

7 Today s Agenda Demand Forecast Regulatory Framework update Corridor Management Siobhan Procter Siobhan Procter Mike Hurley Light refreshments 2011 Annual Planning Report Stephen Leong Upper South Island Grid Upgrade Phasors and Load Monitoring Upper North Island Demand Side Initiatives Simon Todd Stuart MacDonald Siobhan Procter General Discussion and wrap up 7

8 APR 2012 demand forecast a preview APR Roadshow July 2011

9 Background APR 2011 is complete APR 2012 will use a new demand forecast New methodology Some significant changes in results We will consult with industry Transparency Obtain the best available information

10 Progress National and regional forecasts Draft complete Technical review by NZIER See Feedback welcome, preferably by 12 July Model and inputs will be also published on the web Final report due in September GXP-level forecasts In progress We will contact customers to discuss the draft forecasts in July

11 National and regional forecasts

12 Priorities Accuracy in the sense of covering the reasonable range of uncertainty Good process consultation technical review documentation Stability don t want the forecast to flip-flop from year to year but an initial correction may be needed in some areas

13 Seasonality Previous years winter region, winter island, summer, light load all linked New forecast national peaks - winter, shoulder and summer region peaks winter, shoulder and summer region troughs winter, shoulder and summer day and night independent but consistent Future years may be helpful to add even more detail (to support DLR etc) wait and see approach

14 Top down New methodology Forecast at the national level and then allocate down to regions Ensemble approach Don t seek to produce a single perfect model Rather, create a suite of models The range of outcomes across models describes our uncertainty about the future A common approach in e.g. meterorology Step changes Known unknowns Unknown unknowns And then there s the aftereffects of the Christchurch earthquakes

15 Draft results

16 The draft national forecast is lower Annual national peak forecast Prudent 90% POE for first few years, expected growth rate thereafter Inevitable with low peaks in and low economic projections

17 But there is a wide range of uncertainty Annual national peak forecast Demand could grow much faster or much slower

18 Why were peaks so low in ? Various reasons 2008 dry winter and associated high prices Reduced demand at Tiwai Recession New embedded generation offsetting load growth Weather conditions Higher residential electricity prices Electricity efficiency Industrial price response Load control Hard to determine which was most important And note there was vigorous growth in some regions

19 GXP level forecasts

20 Priorities Understand the local situation load control load switching seasonality Incorporate customer feedback use Customer Central website online plots online feedback form provide more relevant and accessible information show summer and winter forecasts separately Please do provide feedback we value local knowledge!

21 Want to find out more? See draft report See model code and input datasets, once published In July we will contact customers to discuss forecasts for their areas Any questions? feel free to contact us

22 Regulatory Update Siobhan Procter Grid Investment

23 Background Electricity Commission established in 2003 The concept of a GUP was born Grid Development submitted 20 GUPs between then and 2010 to a value of $2.7 billion It was a hard road.. In October 2010 regulatory responsibility for major capex transferred to the Commerce Commission This makes sense since Com Com already look after R & R Threshold for enhancement projects requiring a GUP raised from $1.5 M to $5 M from 2012 Rules around GUPs will be captured by an Input Methodology under Part 4 of the Commerce Act

24 Background (cont) Electricity Commission morphed into the Electricity Authority (EA) EGRs becomes Electricity Industry Participation Code Part F becomes Part 12 of the Code including (but not limited to): Transmission Agreements Connection Code GRS Centralised data set Transmission Pricing Methodology EA not required to produce the SoO Investment scenarios will be produced by the MED Internal project to produce demand and generation scenarios underway

25 Objective of Transmission Regulation Section 52A states that the purpose of Part 4 (Part 4 Purpose) is: to promote the long-term benefit of consumers in markets referred to in section 52 by promoting outcomes that are consistent with outcomes produced in competitive markets such that suppliers of regulated goods or services (a) have incentives to innovate and to invest, including in replacement, upgraded, and new assets; and (b) have incentives to improve efficiency and provide services at a quality that reflects consumer demands; and (c) share with consumers the benefits of efficiency gains in the supply of the regulated goods or services, including through lower prices; and (d) are limited in their ability to extract excessive profits.

26 Advantages and Risks Advantages Com Com now regulates all expenditure except: CICs SO expenditure required by EA We have an opportunity to influence new IM Risks Its all new to Com Com IM could last for 7 years so important we get it right

27 Significant issues for submission Major/minor capex threshold - $5M from July 2012, $20M from July 2015 Draft capex IM: Merits review still an option for CC Market benefit test only but unquantified benefits allowed P50 approval final cost approval uncertain Integrated transmission plan 10 year view Far more ex post scrutiny Incentive regime linked to output measures

28 CICs Investment contracts Transpower may enter into an investment contract with implications for grid reliability standards only if (a) the investment contract is consistent with the grid reliability standards or the proposed investment has been approved by the Authority (b) Transpower notifies the Authority of the proposed investment contract.

29 Corridor Management Transpower NZ Ltd July 2011

30 Background Assets located in all Council areas Electricity demand growing under all scenarios Utilisation of existing assets New generation Security of supply

31 Corridor Management The transmission corridor is the physical space occupied by our lines now and in the future. What happens in this space has a direct impact on how we run the network. Our over-riding objective is to identify and protect corridors for future lines and cables and to maintain our ability to use existing corridors appropriately. Availability of corridors is our largest constraint to meeting future needs. Transmission Tomorrow

32 How we identify corridors? Future corridor requirements will continue to be determined by: Demand forecasts Constraints and opportunities on our existing network Existing land use and development Anticipated population growth and changes in land use

33 Why Corridor Management? Capacity of the grid will need to increase significantly over time Manage growth of grid footprint by using existing lines and routes where possible There is a need to manage development that poses a risk to, or is at risk from, the efficient operation of the National Grid

34 Consequences of no corridor Electrical hazard or injury Impact on security of supply Risk to structural integrity Inability to access/maintain Impact on amenity

35 Corridor Management Policy

36 Joint Approach No single solution Each area has different characteristics Case by Case approach required Local Knowledge Opportunity for improved outcomes

37 Opportunities Planning and design Subdivision/site layout Building orientation Visual screening Working together Early consultation to discuss proposals Shared infrastructure corridors

38 Further information Landowner Guides on website: transpower.co.nz/landowners Or contact Mike Hurley on or

39 Christchurch Stakeholder Forum 2011 Annual Planning Report 11 July 2011

40 Role Commerce Commission Trigger for major capital investment (GUP) submissions Part of the Revenue Reset submission Electricity Industry Participation Code Grid Reliability Report Grid Economic Investment Report 10 year forecast maximum fault levels Customers Understand transmission network s ability to supply their needs Our plans for developing the grid Facilitate co-ordination with their own plans Other stakeholders Liaison with local authorities for transmission corridors (existing and possible future) Annual Planning Report Ability of grid to meet forecast demand and generation for next 10 years Potential transmission solutions Publish 31 March 2011 External Internal The Annual Planning Report is intended as a high-level summary document only. It does not imply Transpower has formed a view on whether a transmission (versus a transmission alternative) investment is most economic, or even what the most economic transmission investment would be. Such detailed analysis would only occur in the preparation of a Grid Upgrade Plan. Transpower Co-ordination of development and policy works 2

41 Changes in 2011 Incorporate Transmission Tomorrow (Chapter 2 Facilitating New Zealand s energy future) Indicative longer term transmission development subsections in Regional Plans (align with Transmission Tomorrow) 10 year forecast maximum fault levels at each point of service Reflect new regulatory framework 3

42 Demand Forecast and Generation Scenarios Demand Forecast Derived using historical data, Electricity Commission s prudent peak forecast growth rates, modified to account for customer feedback reports by independent consultants for Grid Upgrade Plans North Island similar to last year South Island increase by about 3% Five regions had significant increase Bay of Plenty, Taranaki, Hawke s Bay, Wellington and Canterbury Generation Scenarios Five scenarios from the Electricity Commission s 2010 Statement of Opportunities updated with recently committed generation 4

43 Key Findings (Canterbury region) Grid Backbone No new transmission issues Regional 1 new issue due to increased demand 2 issues removed (resolved or no longer an issue within the forecast period) Canterbury 5

44 New Issues/Issues Removed in 2011 APR New issue (Year issue arises) Canterbury Southbrook supply transformer capacity (2014) Issues removed Due to change in load forecast Ashley supply transformer capacity Due to project complete Ashburton supply transformer security 6

45 Canterbury Region Upgrading the Reactive Power Controller at Islington (2011) 7

46 Project Calendar Forecast submission dates for projects to the Commerce Commission Year Projects 2011 Islington bus security upgrade Stage 2 Upper South Island grid upgrade plan. Lower Waitaki Valley Reliability Upper Waitaki transmission reinforcement. Note: The investment proposal submission dates are indicative only. Transpower will only submit an investment proposal if it passes the Grid Investment Test. 8

47 The Future Wider audience, including local authorities and Commerce Commission APR evolving More detailed analysis looking out 15 years to support 5 year revenue reset periods Provide indication of the need of transmission corridor plan for Local Authorities Publication Transpower website and CD only Considering two-yearly publication 9

48 10

49 11

50 Other Potential Projects (not yet committed) Indicative Comm Date Bus security upgrade at Islington Additional reactive support in the Canterbury region, or bussing 220 kv circuits between the Waitaki Valley and Christchurch at Geraldine. Addington 11 kv switchboard No.2 replacement. T5/T6/T7 supply transformer replacement A new 220/66 kv supply transformer at Ashburton Ashley supply transformers replacement Bromley New 220/66 kv transformer. 220/66 kv transformers replacement. 11 kv indoor switchboard replacement. Reactor dismantling Hororata 33 kv outdoor to indoor conversion New grid exit point at Hawthornden. Islington Install new 220/66 kv interconnecting transformer. 33 kv outdoor to indoor conversion. TBC Papanui supply transformers replacement Kaikoura Install new 66/33 kv supply transformer. Increase the existing supply transformer thermal capacity. New grid exit point at Rangiora. Springston 33 kv outdoor to indoor conversion. Build a new 220/66 kv interconnection. Install two new 66 kv feeders at Southbrook. New grid exit point at Waimakariri TBC TBC TBC TBC Waipara 33 kv outdoor to indoor conversion Canterbury Region Upgrading the Reactive Power Controller at Islington (2011) Grid Backbone Project Regional Project 12

51 Upper South Island Grid Upgrade July 2011

52 The need Upper South Island is a voltage constrained region. Generation some distance from the USI load There are 2 issues Steady state voltage Dynamic voltage recovery This is not a thermal issue rather its one of voltage pressure to maintain security of supply 2

53 USI region Upper South Island 3

54 N-1 limits USI load limit, MW Winter forecast Winter dynamic voltage stability limit Winter thermal n-1 limit Summer forecast Summer dynamic voltage stability limit Summer thermal n-1 limit 4

55 Need dates N-1 summer limit need date around 2027 N-1 winter limit need date around 2035 N-1 dynamic voltage stability limit need date Will necessitate both static (capacitors) and dynamic reactive support (eg SVC s) or bussing circuits. Unless new generation built in USI region then on-going reactive support will be required. New transmission capacity not necessary until mid-2020 s 5

56 What is the issue? Steady state voltage issues can be resolved using capacitors = cheap and simple Dynamic voltage problem more complex Involves modelling load accurately During faults voltages drop and can stay low for long periods Motors slowing down can require 6-8 times FL current which is usually inductive reactive. If voltage fails to recovery fast enough then network cascade failure can occur 6

57 Dynamic voltage recovery DIgSILENT [s] [s]

58 Options being considered Reactive support Capacitors SVC s STATCOM s Refurbish synchronous condensers Series compensation DVAR devices Reconfigure existing transmission assets New USI generation Demand management especially motor load 8

59 Other investigations High Impact Low Impact (HILP) events at ISL ISL site force majeure study Disaster recovery plan ISL site asset investigation Economic analysis to justify money to mitigate identified HILP risk Outage window issues for 4 circuits into USI region May bring forward N-1 thermal need date. Present analysis ongoing introducing effect of Variable Line Rating (VLR) 9

60 USIGU project timeframe Nov 2009 March 2011 Verify investigation assumptions with generators and lines companies June 2011 Release Request for Information document for consultation (closes July 2011) July 2011 Dec 2011 Decide on short listed options and apply cost/benefit analysis April 2012 Submit investment proposal to CC 1 0

61 Thank You

62 Your feedback is important... What currently works? How can we improve? Please address your feedback to: Grid Development Transpower New Zealand Ltd PO Box 1021 Wellington

63 Annual Planning Report road show - Christchurch RPCs, Phasors, and load monitoring 11 July 2011

64 Overview Christchurch RPC Project purpose and status Phasors Situational awareness Early warning on emerging stability issues Monitor equipment performance Load monitoring Help validate models using in planning the grid

65 Christchurch Reactive Power Controller (RPC) RPC Architecture Future Voltage Management Application Energy Management System (EMS) R_RPC (NI) R_RPC (SI) A_RPC (Nelson) A_RPC (Christchurch) A_RPC (Waitaki) L_RPC (ASB) L_RPC (ISL) L_RPC (BRY) L_RPC (Pound Rd) Scope of Christchurch RPC Project

66 Islington Substation (a future scenario)

67 Christchurch RPC cabinets 2xD400 Christchurch Area and ISL Local RPC (for SVC9 Control room) 2xD400 Christchurch Area and ISL Local RPC (for main ISL Control room) Maintenance PC. 2xCubicles for Islington substation. 2xD400 Main and Backup BRY Local RPC (1 currently with Survalent for HMI FATs). 2xSEL3354 HMI servers. 2xCubicles for Bromley substation.

68 Roll out to other parts of NZ? a concept for Auckland RPC Architecture Regional RPC Future Voltage Management Application Upper North Island Energy Management System (EMS) Area RPC Huntly Auckland North Shore FUTURE (SPARE) Local RPC HUNTLY OTAHUHU PENROSE MT ROSKILL ALBANY HEPBURN RD HENDERSON TBA TBA

69 Monitoring with Phasors Scada X-rays show the bone structure Phasor CT scans show the soft structures (and the bone too)

70 Synchronised recording of phasor data time stamped by GPS clock Real Time measurement of 3 phase V & I both magnitude and phase angle 50 times per second Phasors come from our protection relays Phasor network

71 Unstable oscillation detected

72 System disturbance monitored

73 Load monitoring (Portable)

74 Transient load response E Voltage E Current

75 Measurement vs Model Voltage (pu) Current (Amps) Time (sec) Time (sec)

76 Summary Christchurch RPC Maintains voltages and reserves Maximises capability of existing transmission On line commissioning about to begin Phasors Continuous synchronised real-time monitoring advance warning of emerging stability issues Monitor equipment performance Load monitoring Captures fast-transient response of loads helps improve planning models

77 Questions?

78 Upper North Island Demand Side Initiatives Siobhan Procter

79 Demand Response Demand Response (DR) is a term used to describe the action taken by electricity consumers to reduce their net demand by responding to a signal This can be done by either a direct reduction in demand, for example turning off refrigeration units or by increasing supply into the system, for example using standby generation.

80 Demand Response 12 Transmission Load (MW) Transmission capacity limit 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Call Period Demand without DSP Demand managed with DSP

81 Demand Side Response Uses Interruptible Load Reserve (ILR) - bid into the electricity market and generally hot water ripple control Co-ordinated control of load to reduce transmission charges (again typically hot water ripple control) Reducing energy costs retailers and end use consumers who are exposed to the spot market may voluntarily reduce demand to avoid high prices Grid support to reduce the peak load and either support or defer grid investment.

82 Demand Side In NZ Well established reserves market makes use of interruptible load Very little progress in terms of advancing active demand participation in the NZ electricity market UK has 2.5 GW of contracted demand side PJM has over 3 GW Many markets now provide for demand side response to wholesale and retail price signals NZ initiatives in development over last 10 years: Demand Side Bidding and Forecasting Dispatchable Demand

83 DR - Grid Support Contracting DR for Grid Support can defer the need for transmission investment be used as a risk management tool Transpower ran a Demand Side Participation pilot and trial in the Upper South Island region in 2007 and 2008 Transpower also secured funding of the USI load controller in 2009

84 UNI Demand Side Initiatives IN 2010, the Electricity Commission approved the UNI Dynamic Reactive Support Investigation Grid Upgrade Plan. The proposal specifically allowed for the investigation of demand-side initiatives to allow more flexible management of the grid in the region during major project commissioning and provide an important contingency measure against uncertainties both in the growth and nature of regional demand and the requirement for reactive support

85 UNI Demand Side Initiatives (cont) The Grid Upgrade Plan proposed a suite of dynamic reactive support investments including 2 statcoms and a Regional Power Controller Demand response could assist with: Contingency measure during construction and commissioning of NIGUP and NAaN Potentially defer future investment in dynamic reactive support as load grows in the Auckland region

86 UNI DSI Project Demand Side Initiatives approved funding of $12M Demand side product 60 MW Demand side platform UNI Load Controller Late delivery Potential deferral Dispatch product Potential extension

87 Demand Response Product RFP issued in March seeking 60 MW of demand response made up of 10 MW blocks Anticipated that proposals would include a mix of aggregated load and/or generation Aggregators are parties that engage directly with providers of DR: Will contract for a number of sources at different locations Sources may be manufacturing, cold store load etc May need to contract 13 MW to deliver 10 MW of reliable DR

88 How will it work DR will be used as a pre event contingency product Triggered by SO load forecast breaching a pre-defined capacity limit In USI pilot and trial all comms were manual SMS Fax Phone Given potential number of blocks in UNI, process needs to be automated and more sophisticated

89 DSI Platform investigation Investigate solutions to coordinate dispatch of demand side initiatives New technology and/or adapting technology to the NZ context RFP issued in April and closed end of May currently under evaluation

90 DSI Platform A technological and/or IT architecture solution which will enable the co-ordination and management of the DR product Interface between SO and DR suppliers No requirement to change market systems Optimisation capability to ensure lowest cost and best fit of DR to call requirement Potentially assist in development of a demand side market

91 DSI Platform simplistic view

92 Indicative Timetable RFP closed 27 May 2011 RFP evaluation complete 30 June 2011 Contracts awarded 29 July 2011 Testing complete 25 Nov 2011 Testing report published Dec Likely contract period ( )

93 Conclusion UNIDSI project seeks to secure demand response as a grid support product Effectively will test the practicalities and economics of DR as a transmission alternative Establishing a DR platform may provide an exciting opportunity to increase the level of active demand side participation in the wholesale electricity market

94 Christchurch Stakeholder Forum: Wrap-up Christchurch 11 th July 2011

95 Further Information

96 Ongoing Updates