MARKET MATTERS HVDC UTILISATION REPORT OCTOBER 2018

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1 HVDC Utilisation In late 2016 we published a report covering what restricts HVDC north transfer 1. We are now publishing monthly updates on the market aspects that restricted HVDC north transfer, and some key information regarding HVDC transfer during the past month. This is to inform responses to questions around why, at times of favorable South Island hydrology, the HVDC has only transferred in the order of MW north, despite a capacity of 1,200MW north. This report focusses on energy transfer and forward reserve sharing in the northwards direction. If energy is primarily southwards, for instance during a dry year, then Transpower generally publishes extra reporting during such times. Key points for October Continuing declining hydro storage levels throughout the month saw South Island generation reduce further. This in turn saw average HVDC northwards utilisation drop to 33%. It was 36% over weekday peak demand periods. - Average energy transfer over peak demand periods was 241MW, compared to 333MW last month. - The HVDC was the binding risk for 194 trading periods. It was nearly always the ECE that was binding (it was the CE for 4 trading periods), often in conjunction with a North Island generator. i.e. it was a joint risk setter. This resulted in price separation of more than $20/MWh on 21 occasions. - While there were 10 circuit outages during the month limiting HVDC capacity at times, none of these restricted the HVDC utilisation. 1. HVDC northwards utilisation for October 2018 HVDC utilisation takes into account the energy transfer, instantaneous reserves shared in the same direction (north) and modulation risk. Since the introduction of the National Market for Instantaneous Reserves (NMIR) in late 2016, sharing of reserves between the islands has been possible. HVDC energy transfer and reserve sharing are co-optimised as the market system solves for the least cost combination of energy and reserves to meet system demand. Energy transfer across the HVDC can be lower if increased reserve sharing creates a greater market benefit. The modulation risk (modelled as 30MW) accounts for the amount the HVDC can be away from its setpoint due to modulating to keep the North and South Island frequencies close together. The Modulation risk may be changed in realtime to manage real time security risks presented by realtime monitoring tools The graph below shows the HVDC bipole max available capacity, HVDC energy transfer, reserves shared north + modulation risk during October It shows, in general, with the HVDC transfer being mostly northwards, the overall average utilisation was 33% and the average utilisation during weekday peak demand periods 2 was 36%. 1 Please see 2 Weekday peak demand periods being 07:30-08:00 and 18:00-18:30, Monday-Friday. 1

2 01/10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/2018 MARKET MATTERS 1,200 HVDC Utilisation October ,000 HVDC Transfer and Utilisation (MW) Date HVDC Bipole Max HVDC Transfer Sent North+ Shared Reserves Sent to NI + Modulation Risk HVDC Transfer Maximum transfers were around MW, compared to MW for September. Typical transfer during peak demand periods was around MW for the majority of the month, compared to MW last month. Overnight south transfer occurred regularly with a maximum of 412MW south. There were no planned or unplanned outages to the HVDC and the reductions to the HVDC maximum available capacity were only as a result of planned outages to several lower North Island circuits. The graph below shows the spread of HVDC northwards utilisation during October 2018 and for all months since December It shows that utilisation of the HVDC, through October 2018, for north transfer and shared reserves sent north was mostly in the range of 0-37%. This is across all trading periods, including periods when the HVDC was transferring energy south. 0% utilisation is generally where the HVDC is transferring energy southwards. 2

3 For comparison, the HVDC northwards utilisation across all months from December 2016 (the first full month after NMIR implementation) to the end of October 2018 is also shown in the graph above. This includes many periods of HVDC south transfer. This shows that October 2018 has a generally lower northwards utilisation than the average since December Reverse reserve sharing The HVDC can also share reserves in the reverse direction to energy transfer, subject to some constraints. While reverse sharing is also important and utilising the capability of the HVDC, it doesn t affect the overall northwards capacity. Reverse sharing of reserves during HVDC north energy transfer has also been at generally low levels. From December 2016 to the end of October 2018 the average amount of reverse reserve sharing during north energy transfer has been 23MW of FIR and 38MW of SIR. This compares to an average forward sharing of reserves during north energy transfer of 105MW of FIR and 127MW of SIR. Constraints on HVDC utilisation HVDC utilisation depends on the supply and demand for energy and reserves, as well as constraints, including the HVDC maximum available capacity. The key factors limiting utilisation are: a) Transmission constraints (including AC and DC constraints), b) Reserve costs associated with increased HVDC transfer, and c) Offer behaviour to avoid price separation caused by either of the above 2 factors. 3

4 a) Transmission constraints Transmission constraints limit the export of generation below the constraint. A constraint on the HVAC network can restrict the energy available for transfer across the HVDC. Additionally the HVDC transfer limit can be set as a result of outages of reactive equipment at Benmore and/or Haywards or through reduced voltage operation of the HVDC. Outages affecting HVDC northwards maximum available capability throughout October 2018 are listed below. For details of how these affected the max available capability please refer to our earlier document from November 2016 or the HVDC bipole operating policy 3. The maximum transfer capability can be found on WITS each day. The HVDC maximum available capability can also be seen as the mid blue area in the HVDC utilisation graph. Outage Block Start End Type BPE_BRK_ :08: :41:07 continuous BPE_TKU_ :38: :18:15 continuous BPE_TKU_ :39: :18:22 continuous HAY_SC_ :36: :56:21 continuous BPE_BRK_ :02: :32:53 continuous HAY_SC_7_T :05: :52:43 continuous BPE_TKU_ :36: :31:30 continuous BPE_LTN_WIL_ :05: :30:43 continuous BPE_PRM_ :10: :57:12 continuous HAY_PRM_ :10: :20:17 continuous b) Reserve costs associated with increased HVDC transfer i. The HVDC maximum available capacity can restrict the sum of energy transfer and forward reserve sharing (for each of FIR and SIR). When the sum of energy transfer and forward shared reserves approaches the HVDC maximum available capacity, the amount of reserve sharing from the sending island becomes restricted by the remaining capacity on the HVDC. Additional energy transfer would then require more reserves from the receiving island to replace reserves from the sending island. ii. The HVDC may also be the binding risk for either FIR or SIR (or both). When this occurs there is not sufficient reserve (covering AC risks) already procured in the receiving island so additional HVDC transfer requires additional reserves to be procured from the receiving island. Either of these 2 situations above can lead to energy price separation between islands due to the co-optimisation of energy and reserves. The extent of price separation will depend on the price of reserves in the receiving island. 3 The HVDC bipole operating policy can be found on Transpower s website. You can access the policy by logging into your Transpower customer account and following the link: 4

5 Our report from July 2018 had 2 examples to help explain the 2 situations above. HVDC binding risk and price separation for October 2018 The number of trading periods when the HVDC was the binding risk during the month of October 2018 is set out in the table below. Number of trading periods when DC the Number of trading periods when DC was the was binding risk for FIR binding risk for SIR This led to price separation on 194 occassions. The extent of this price separation is summarised below. Price separation ($/MWh) Number of occurrences <$ $10-$20 51 $20-$30 12 $30-$40 2 $50-$60 4 >$100 3 The maximum price separation of $119.94/MWh was on 7 October for the 18:00 trading period. c) Offer behaviour to avoid price separation caused by either of the above 2 factors Price separation can result in financial loss for participants who are buying energy at comparatively high prices and selling energy at comparatively lower prices (i.e. they are short to high energy prices). Participants may structure their offers in order to avoid price separation. Participants must also allow for price variation/price uncertainty in the period between gate closure (an hour before real-time) and real-time. This variation or uncertainty can be as a result of inaccuracies in the load forecast, inaccuracies in offers of wind generation and changes to other offers. The extent of price separation avoidance will depend on the economic risk how likely is the price separation to be significant. For price separation due to the HVDC risk binding, participant offer behaviour may depend both on how close the HVDC is to binding, as well as how close the HVDC reserve requirement is to incurring high reserve costs. Below are 2 factors that may influence such behaviour. 5

6 1/10/2018 2/10/2018 3/10/2018 4/10/2018 5/10/2018 6/10/2018 7/10/2018 8/10/2018 9/10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/ /10/2018 Reserve Requirements (MW) MARKET MATTERS i. Reserve shortfalls (not enough North Island reserves to support extra transfer over the HVDC) At times there may be insufficient North Island reserves (FIR and/or SIR) offered at any price to support higher levels of HVDC transfer. Throughout October 2018 there was no shortfall of reserves. ii. Economic cost of extra SI energy and economic cost of extra reserves This is where the cost of extra North Island energy is cheaper than an extra MW of South Island energy or where the cost of extra North Island energy is cheaper than an extra MW of South Island energy plus an extra MW of North Island reserves. The graph below shows the limiting factors during the evening peak (18:00-18:30 trading period) over the month of October The limiting factors are: High SI energy costs compared to NI energy costs, when the red lines are below the corresponding blue lines High SI energy costs plus NI reserves costs compared to NI energy costs, when either of the red lines are equal to the corresponding blue line. When the red line is equal to the blue line the DC is the risk setter for FIR and NI FIR may be limiting the HVDC transfer to the north. When the red dotted line is equal to the blue dotted line the DC is the risk setter for SIR and NI SIR may be limiting the HVDC transfer to the north. 400 Total and HVDC Reserve Requirements for the 18:00 trading periods - October 2018 DC FIR Required DC SIR Required 350 NI FIR Required NI SIR Required Date 6

7 Price ($/MWh) MARKET MATTERS Note: At times the DC reserve (either DC FIR and/or DC SIR) required may be zero, this indicates that HVDC transfer may be southwards or net free reserves and/or NI AUFLS is more than sufficient to cover the north transfer for a CE and/or ECE event. 2. Reserve costs The graph below shows NI FIR and SIR prices thoughout October Prices were lower than for last month, averaging $1.57/MWh for FIR and $1.14/MWh for SIR compared to $2.44/MWh for FIR and $2.95/MWh for SIR in September. There were however some price spikes for FIR occuring on the 7th, 11th and 15th. The FIR price on the 15th (not shown on the graph) reached $379.65/MWh for the 07:30 trading period. 110 NI FIR and SIR prices October Reserve Price Six Sec Reserve Price Sixty Sec 3. Hydro storage over October 2018 Hydro storage throughout most of October 2018 was below average (dark blue line compared to the grey line on the graph below). The month started with storage of 1,945 GWh or 86% of average and finished with 1,812 GWh of storage or 76% of average. The NZX daily summary as at 31 October is shown below and shows how hydro storage varied through October. 7

8 4. Energy transfer (GWh 4 ) Source: NZX Above average inflows to the Southern Lake catchments for the 2018 calendar year to date have resulted in the net transfer north on the HVDC being much more than all of For comparison with a wet year (2016) the net transfer at the end of October 2016 was 3,137 GWh. HVDC Transfer Net (GWh) 2018 to week ended 28 October , Calendar year 1, Calendar year 3,837 The graph below shows the net north transfer of energy on the HVDC for the year to date and the last 2 years for comparison 4 1 GWh is roughly equivalent to the annual consumption of 125 households (based on an 8,000kWh annual consumption) 8

9 Net Transfer North (GWh) MARKET MATTERS 4,000 3,800 3,600 3,400 3,200 HVDC Net Transfer North (GWh) for 2016, 2017 and 2018 year to date 2016 Cumulative HVDC Transfer North (GWh) 2017 Cumulative HVDC Transfer North (GWh) 2018 Cumulative HVDC Transfer North (GWh) 3,000 2,800 2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1, Jan Feb Mar Apr Apr May Jun Jul Aug Sep Oct Nov Dec Jan Month The graph below shows the energy transferred over the HVDC, and direction of transfer, for each week of the year to end of October