Pricing Event Reports - June 2013

Electricity Pricing Event Report – Saturday 30 June 2013

Market Outcomes: South Australian spot prices reached $1,906.40/MWh for trading interval (TI) ending 0000 hrs on Sunday morning.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below.

Detailed Analysis:  5-Minute dispatch prices reached $11,048.03/MWh in South Australia for dispatch interval (DI) ending 2345 hrs on Saturday, when the demand increased by 224 MW from DI ending 2330 hrs to 2345 hrs, due to hot water load pick up. This additional load represented a 14% increase in the South Australian demand.

During the high priced trading interval only 127 MW of wind generation was available. (During periods of low wind generation, prices in South Australia are likely to spike when there is a sudden demand increase.)

In an earlier offer, 22 MW of generation capacity from Osborne Power was moved from a price of $46.01/MWh to $11,048.03/MWh from DI 2335 hrs. In a rebid received at 2333 hrs, 165 MW from Torrens Island PS was rebid from $300/MWh and less, to bands priced at more than $11,000/MWh from DI 2345 hrs.

Flow towards South Australia on the Heywood interconnector could not be increased as it was already exporting at its limit of 460 MW in the DI prior. Target flow on the Murraylink interconnector increased from 137 MW to 173 MW from DI 2340 hrs to 2345 hrs. Generation priced at $11,048.03/MWh had to be cleared from Osborne Power for DI ending 2345 hrs to meet the additional load, and offer set the price for DI 2345 hrs. 102 MW of generation capacity, offered at around $300/MWh, was available from Ladbroke PS and AGL Hallet, but the units needed more than one dispatch interval to synchronise.

The 5-minute prices reduced to $67.58/MWh in the subsequent DI, when the non-scheduled generating units at Angaston PS and Point Stanvac started generating (up to 101 MW) in response to the high price. In addition 165 MW of generation capacity from Torrens Island PS was rebid to the market floor price from DI 2350 hrs.

The high 30 minute spot prices for South Australia was not forecast in the 2330 hrs pre-dispatch schedule, as it was due to a sudden load increase and a rebid of generation capacity within the trading interval that caused a spike in the 5-minute dispatch price.


Electricity Pricing Event Report – Friday 21 June 2013

Market Outcomes: Spot prices in South Australia and Victoria reached $2,217.13/MWh and $2,026.38/MWh for Trading Interval (TI) ending 1000 hrs respectively, followed by a spot price of $1,937.34/MWh in Victoria for TI 1100 hrs. Prices collapsed to -$156.32/MWh and -$47.61/MWh in South Australia and Victoria for TI 11130 hrs. South Australia recorded a further high price of $2,088.82/MWh for TI 1530 hrs. 

Negative prices were observed in Tasmania for TIs 1100 and 1130 hrs, when prices reached -$334.24/MWh and -$250.62/MWh respectively. 

FCAS prices in Tasmania were significantly higher than usual for TIs ending 1230 hrs to 1530 hrs, but did not reach the threshold value of $3,000/MWh for reporting purposes. 

Counter price flows caused negative residues of approximately $646,000 to accumulate on the Victoria to New South Wales directional interconnector during the day. AEMO managed negative residues from 1050 hrs to 1140 hrs by reducing the flow on the interconnectors towards New South Wales. Approximately $96,000 of negative residues accumulated on the Victoria to South Australia directional interconnector during the day. The residues were managed from 1435 hrs to 1535 hrs by reducing the flow on the interconnectors towards South Australia. 

FCAS prices for the other regions and energy prices in Queensland and New South Wales were not affected.

Further details are provided below.

Detailed Analysis:  5-Minute prices reached $12,900/MWh in South Australia and $11,784.04/MWh in Victoria for dispatch interval (DI) ending 0945 hrs, when

  • Hazelwood PS unit 7 tripped from 135 MW at 0937 hrs and
  • 600 MW was tripped (DI 0940 hrs) and then withdrawn from Yallourn PS as part of an industrial action campaign
  • 40 MW from Northern PS unit was rebid to $12,194/MWh

A generation offer of $12,899.80/MWh from Eildon PS unit 2 had to be cleared to meet the demand in Victoria and South Australia for DI 0945 hrs. Lower priced generation offers were available from fast start units that needed more time to synchronise. In addition 524 MW of generation from Murray PS, offered at the market floor price, was constrained off by the constraint N>>V_DBUSS_1. The constraint avoids the overload of a Murray-Dederang 330 kV line (south flow) for trip of the parallel line.

New South Wales was exporting 608 MW to Victoria during DI 0945 hrs, with higher export limited the N>>V_DBUSS_1 constraint. Basslink was exporting 302 MW to Victoria during the dispatch interval, and further export was limited by an FCAS constraint that ensured sufficient Fast Raise Services were enabled for a Mainland generation event. 

5-Minute prices reduced in both regions in the next DI when

  • 1289 MW was rebid to the market floor price in Victoria
  • 145 MW was rebid to the market floor price in South Australia
  • 104 MW of non-scheduled generation from Angaston and the Port Stanvac units came on-line
  • the aluminum smelter at Point Henry in Victoria reduced load by 111 MW (presumably in response to the high price) and
  • fast start units in Victoria and South Australia were synchronised and received generating targets (total of 339 MW).

The 5-Minute price again spiked at $12,899.86/MWh in Victoria for DI 1035 hrs, when the constraint CA_SPS_40D62A5B_01 was invoked and constrained off more than 500 MW of generation in Victoria. The constraint also reversed the flow on Basslink from 147 MW to Victoria, towards Tasmania, and limited flow to Victoria on the Heywood interconnector. The constraint was required to manage the load on the Hazelwood –Yallourn 220 kV (nr.1) line, on trip of the nr. 2 line, as a result of the withdrawal of generation from Yallourn PS. The 5-minute price was set by an offer from McKay PS in Victoria. In addition the N>>V_DBUSS_1 constraint limited flow from NSW to 207 MW during the DI.

In the two DIs following the high 5-minute price, 1677 MW of generation capacity in Victoria and 461 MW of generation capacity in South Australia were rebid to bands priced at -$1,000/MWh. In addition 1108 MW of generation capacity in Tasmania was rebid to close to the market floor price from DI 1045 hrs. The extensive rebidding of generation to negative price bands reduced spot prices to -$334.24/MWh in Tasmania, and ensured a spot price in Victoria of under $2,000/MWh, after the 5-minute price of $12,899.86/MWh that was reached at the start of TI 1100 hrs. 

All three regions recorded negative prices for TI 1130 hrs, when 1183 MW of generation in Tasmania and 450 MW of generation from Loy Yang PS A were rebid to the market floor price from DI ending 1115 hrs.

The high South Australian spot price for TI 1530 hrs was due to a spike in the dispatch prices in DI 1520 hrs. 70 MW of generation capacity from Northern PS unit 1 was rebid to $12,194.44/MWh, and 80 MW of capacity, previously offered at $298/MWh, was withdrawn from the market. Energy transfer from Victoria to South Australia was reduced from 226 MW to 160 MW by a negative residue management constraint that was invoked between 1435 hrs and 1535 hrs. An energy offer at this price had to be cleared from Northern PS to meet the South Australian demand.  Lower priced generation offers were available from fast start units that needed more time to synchronise, and from the AGL Hallett unit that submitted a rebid offering its full capacity at -$1,000/MWh, but was limited by its ramp up rate. Dispatch prices reduced in the next DI when 98 MW of non-scheduled generation from Angaston and the Port Stanvac units came on-line, and the AGL Hallett unit reached its maximum output of 152 MW.

The unusual spot prices for the affected regions were not forecast in the pre-dispatch schedules, as these pricing outcomes were mostly due to the tripping of the Yallourn units, the tripping of the Hazelwood PS unit 7 and the rebidding that occurred during the affected trading intervals.


Electricity Pricing Event Report – Sunday 23 June 2013

Market Outcomes: Tasmanian FCAS prices (sum of all services) reached $8,731.83/MWh for trading interval (TI) 0830 hrs.

Energy prices and FCAS prices for the other NEM regions were not affected. 

Further details are provided below.

Detailed Analysis: During TI 0830 hrs the average target flow for Basslink averaged 7.4 MW towards Tasmania. At these transfer levels Basslink is unable to transfer FCAS, and the FCAS requirements in Tasmania have to be met by enabling generation from local units.

The FCAS price for lower regulation services reached $12,900/MWh for dispatch intervals (DIs) 0805 hrs to 0820 hrs.

A step change in the offer profile of the regulation services in Tasmania resulted in only 24 MW of lower regulation services offered at less than the market price cap. Lower regulation services of 50 MW had to be enabled in Tasmania to the meet the regulation requirement, which resulted in offers of $12,900/MWh for lower regulation services contributing to the FCAS prices during the DIs 0805 hrs to 0820 hrs.

From DI 0825 hrs Hydro Tasmania rebid 26 MW of lower regulation services to bands priced at $0.20/MWh and 56 MW to bands priced at $3.00/MWh. FCAS prices returned to normal levels when the rebid reduced the 5-minute price of these services to $0.20/MWh. 

The high FCAS prices for Tasmania were forecast in the 0800 pre-dispatch schedule.


Electricity Pricing Event Report – Thursday 20 June 2013

Market Outcomes:  Queensland spot prices reached $1,916.41/MWh and $1,658.51/MWh for trading interval (TI) ending 0730 hrs and 0800 hrs respectively. The FCAS prices (sum of all services) reached $2,076.84/MWh and $4,327.79/MWh for the same TIs. 

FCAS and energy prices for the other NEM regions were not materially affected by this event. 

Further details are provided below. 

Detailed Analysis:  5-Minute dispatch prices reached $11,063.78/MWh and market price cap for dispatch interval (DI) ending 0730 hrs and 0735 hrs respectively.

Queensland energy price increased significantly when the demand increased to its morning peak of 6679.11 MW at DI 0735 hrs. The Calvale – Tarong (8811) 275 kV line in South Queensland was on a scheduled outage from 1530 hrs on 19 June 2013. This outage is part of the initial phase of the project to build two new transmission lines between Halys and Tarong.

The constraint Q_CS_1100, that limits the power transfer from Queensland Central to Queensland South to 1100MW, was binding due to increased flow between the two sub-regions. This resulted in majority of the Queensland generation as well as interconnector flow being constrained between DI 0635 hrs to DI 0740 hrs.

From DI ending 0730 hrs, Millmerran rebid a total of 110MW of generation priced at -$1000/MWh to $12,900/MWh and contributed to the setting of the high energy price of $11,063.78/MWh. The revised offer was received at 0720 hrs, with the reason given as “07:19 A PRICE ABOVE PD –SL”. Generation capacity offered at lower price was either fully dispatched, limited by their ramp rates or a fast start plant that needed more than one DI to synchronise.

At DI ending 0735 hrs, the market cap price was set by an optimisation of the energy and FCAS offers as the requirement of both energy and FCAS increased. Fast start plants with generation capacity offered at lower price were not given a target due to fast start profile modeling in the NEM dispatch engine.

During the event, the Tamworth – Armidale (86) 330 kV line in New South Wales was on an unplanned outage from 1627 hrs on 19 June 2013 due to issues with the Tamworth circuit breaker. Consequently, this line outage limited the transfer to Queensland on the interconnectors. The FCAS Raise Services requirement and price in Queensland increased when more northwards flow is required on the interconnectors during the morning peak demand period when Queensland Central generation was constrained off. 

Between DI 0740 hrs to DI 0800 hrs, extensive rebidding of generation to negative price bands occurred. Up to 4312 MW of generation capacity was rebid to the market floor price, which brought the total generation capacity offered in the negative price bands to 6413 MW at DI 0800 hrs. This resulted in the 5-minute dispatch prices in Queensland to collapse to between -$1,000/MWh and -$999.99/MWh from DI 0750 hrs to 0800 hrs. Despite the negative dispatch prices, the 30-minute spot price for TI 0800 hrs average $1,658.51/MWh.

Spot prices returned to the normal range from DI 0805 hrs when approximately 3042 MW of generation capacity offered at negative prices was rebid to higher price bands.

The high 30-minute spot prices for Queensland was not forecast in the 0700 hrs pre-dispatch schedule as the right-hand-side of the constraint Q_CS_1100 was approximately 440 MW more relaxed in pre-dispatch than in dispatch. Hence, the constraint did not bind and constrain Queensland generation as well as interconnector flows.


Electricity Pricing Event Report – Wednesday 19 June 2013

Market Outcomes: South Australia recorded a 30-minute spot price of $2,015.13/MWh for trading intervals (TIs) ending 1930 hrs on Wednesday.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below.

Detailed Analysis:  The 5-minute dispatch price reached $11,090.80/MWh for dispatch interval (DI) 1930 hrs.

From DI ending 1930 hrs, AGL SA rebid 120 MW of generation priced between $199.99/MWh and $299.80/MWh from the Torrens Island PS to $11,090.80/MWh. The revised offer was received at 1922 hrs, with the reasons given as “19:20A CHG IN FORECAST::1930 5PD DEMAND DECREASE VS30PD <35MW“, and “19:20A CHG IN FORECAST::5PD DEMAND DECREASE SA V 30PD <30MW”.  The rebids increased the dispatch prices from $199.99/MWh (DI 1925 hrs) to $11,090.80/MWh (DI 1930 hrs), when 3 MW of this expensive generation was cleared from the Torrens Island units to meet the demand.

The rebidding occurred during the evening peak, when the South Australian demand was high at around 2220 MW, with low wind generation. The shape of the offer curve contributed to the price spike, as there was no generation offered in the $300/MWh - $11,000/MWh price bands during the affected trading intervals.

During the high-priced DI approximately 675 MW was exported to South Australia on the interconnectors. The Heywood interconnector was at its upper transfer limit of 460 MW, and Murraylink was limited by the constraint V^SML_NSWRB_2, which avoids voltage collapse for the loss of the Darlington Point to Buronga (X5) 220kV line.

The dispatch prices were reduced to $96.45/MWh in the DI following the price spike, when approximately 87 MW of non-scheduled generation from Angaston PS and Port Stanvac came on-line. The units can reach full capacity within one DI and typically start generating in response to the high dispatch prices.

The high spot prices were not forecast in the pre-dispatch schedule for TI 1900 hrs.  The high spot price was not forecast as it was caused by rebids that were received after the pre-dispatch run.

 


Electricity Pricing Event Report – Tuesday 18 June 2013

Market Outcomes:  South Australia recorded 30-minute spot prices of $2,099.99/MWh and $1,918.70/MWh for the trading intervals (TIs) ending 1900 hrs and 1930 hrs on Tuesday.

South Australia recorded 30-minute spot prices of $2,099.99/MWh and $1,918.70/MWh for the trading intervals (TIs) ending 1900 hrs and 1930 hrs on Tuesday.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below.

Detailed Analysis:  The 5-minute dispatch prices reached $12,194.41/MWh for dispatch interval (DI) 1845 hrs, and $11,090.80/MW for DI 1930 hrs.

Origin Energy rebid 72 MW from its Ladbroke Grove and Quarantine PS units from -$1,000/MWh to $12,194/MWh from DI ending 1845 hrs. The revised offer was received at 1837 hrs, with the reason given as “CONSTRAINT MGMT – V>S_460”. The rebid increased the dispatch prices from $95.86/MWh (DI 1840 hrs) to $12,194.41/MWh (DI 1845 hrs), when 20 MW of this expensive generation was cleared from the Quarantine units to meet the demand. 

AGL SA rebid 100 MW of generation from the Torrens Island PS from -$1,000/MWh to $11,090.80/MWh from DI ending 1930 hrs. The revised offer was received at 1923 hrs, with the reason given as “CHG IN DISPATCH :: DEMAND DECREASE VS PD [SA] “.  The rebid increased the dispatch prices from $85.33/MWh (DI 1925 hrs) to $11,090.80/MWh (DI 1930 hrs), when 43 MW of this expensive generation was cleared from the Torrens Island units to meet the demand.

The rebidding occurred during the evening peak, when the South Australian demand was high at around 2200 MW, with almost no wind generation available. The shape of the offer curve contributed to the price spike, as there was no more than 27 MW of generation offered in the $101/MWh - $11,000/MWh price bands during the affected trading intervals.

During the two high-priced DIs approximately 655 MW was exported to South Australia on the interconnectors. The Heywood interconnector was at or close to its upper transfer limit of 460 MW, and Murraylink was limited by the constraint V^SML_NSWRB_2, which avoids voltage collapse for the loss of the Darlington Point to Buronga (X5) 220kV line.

The dispatch prices were reduced to $73.76/MWh and $111.07/MWh respectively in the DIs following the price spikes, when approximately 110 MW of non-scheduled generation from Angaston PS and the Port Stanvac units came on-line. The units can reach full capacity within one DI and typically start generating in response to the high dispatch prices.

Spot prices were forecast to reach $12,000/MWh in earlier pre-dispatch schedules, but the high prices disappeared in the schedules published in the trading intervals immediately before the price spikes. This was due to lower cost generation offered into the market in response to the high prices. Spot prices of around $2,000/MWh eventuated in dispatch, due to the rebidding of capacity after the respective schedules were published.


Electricity Pricing Event Report – Monday 17 June 2013

Market Outcomes:  Queensland spot prices reached $4,334.62/MWh for trading interval (TI) ending 0730 hrs. A further high spot price of $2,222.33/MWh occurred for TI 1730 hrs. 

FCAS and energy prices for the other NEM regions were not affected by this event. 

Further details are provided below.

Detailed Analysis:  5-Minute dispatch prices reached the market price cap for dispatch interval (DI) ending 0710 hrs, and $12,899.83/MWh for 0715 hrs. 

The outage constraint Q>>BRTR_MRTX5_MRTX4 was invoked from DI 0705 hrs to manage the planned outage of the Braemar-Tarong (8815) 275 kV line. The constraint manages the post-contingent flow on the Middle Ridge 330/275 kV nr. 4 transformer. 

The flows on the Middle Ridge 330/275 kV transformers and the Greenbank-Middle Ridge (8848) 275 kV line increased significantly when line 8815 was removed from service. The outage constraint reduced the generation from the two Millmerran units by 1 MW/min (per unit) as per the offered ramp down rates. The Oakey GTs could relieve the constraint but the units needed 5 minutes to synchronise.  The constraint reduced the target flow to Queensland on the QNI interconnector from 166 MW to 7 MW, but 54 MW had to be transferred to meet the Queensland demand. This resulted in the constraint violating for DI 0710 hrs, as the desired outcomes to satisfy the constraint could not be achieved.  

The high dispatch price was followed by a price of $12,899.83/MWh in the next DI, when a generation offer at this price was cleared from Gladstone PS unit 4. Lower priced generation capacity was available from fast start plant, but the units required more than one dispatch interval to start generating.  Lower priced generation capacity was available from the Callide C and Stanwell units, but the increase in output was restricted by the ramp up rates of the units.   

During the high priced intervals, constraints that manage the post-contingent load on a Lismore-Dunoon line (9U6 or 9U7) on trip of the other Lismore-Dunoon line, limited energy flows to Queensland on the Terranora interconnector to 68 MW and 56 MW respectively. 

In response to the high prices 320 MW of generation from Braemar units 6 and 7 was rebid from $455/MWh to -$1,000/MWh from DI 0715 hrs 26 MW of generation from Braemar units 6 and 7 was rebid from $12,500/MWh to -$1,000/MWh from DI 0715 hrs 500 MW of generation from Wivenhoe PS was rebid from bands priced at over $7,000/MWh to $0/MWh from DI 0720 hrs and 150 MW from Oakey PS  unit 1 was rebid from $427/MWh to -$1,000/MWh from DI 0720 hrs.

The 5-minute prices reduced to $46.78/MWh for DI 0720 hrs, when Qakey PS unit 1 received a dispatch target of 23 MW and Wivenhoe PS and the Braemar units 6 and 7 were issued with dispatch targets.

Dispatch prices reached $12,900/MWh during DI 1730 hrs, when the Queensland demand increased by 56 MW. The Braemar-Tarong (8815) line was still out of service and the outage constraint restricted flow to Queensland, and reduced the output from the Millmerran units by 17 MW. The $12,900/MWh price occurred when 11 MW of generation offered at this price was cleared from Gladstone PS to meet the demand increase. Lower priced generation capacity was available from fast start plant and from Stanwell unit 4 and Callide C unit 3. The fast start units required more than one dispatch interval to start generating, whilst the output from Stanwell 4 and Callide C units increased by only 35 MW due to the low ramp up rates of the units.

Dispatch prices reduced to $71.75/MWh when the demand reduced by 111 MW in the next DI. In addition the fast start units at Oakey and Roma Power Stations finished synchronising in the DI and started generating from DI 1740 hrs.

The Braemar-Tarong (8815) line was returned to service at 1755 hrs and the outage constraint was revoked at 1800 hrs.

The high 30-minute spot prices for Queensland were not forecast in the pre-dispatch schedules.  The high prices were caused by the action of the outage constraint in response to changes in line flows, and in pre-dispatch the constraint equation uses sub-regional demands instead of line flows.


Electricity Pricing Event Report – Friday 7 June 2013

Market Outcomes:  South Australia recorded a spot price of $1,915.54/MWh for the trading interval (TI) ending 1900 hrs on Friday.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below. 

Detailed Analysis:  5-Minute dispatch prices reached $11,090.79/MWh for dispatch interval (DI) ending DIs 1840 hrs.

From DI 1830 hrs, 110 MW of generation capacity from Northern PS unit 2 was rebid from bands priced at less than $300/MWh to $12,194.44/MWh. From DI 1835 hrs, 42 MW of generation from Pelican Point CCGT was rebid from $50.80/MWh to the market price cap.

An offer of $11,090.79/MWh from Quarantine PS was cleared to meet the demand at 1840 hrs.

The high dispatch prices can mostly be attributed to the rebids and the steepness of the offer curve of South Australian generation capacity.  During the DI in which the high priced occurred:

1408 MW of capacity was offered at less than $100/MWh,

  • 120 MW was offered at $199.99/MWh,

  • 0 MW was offered between $200 and $11,000/MWh

  • 571 MW was offered at more than $11,000/MWh. 

Exacerbating the situation was the low amount of wind generation available over the evening peak – the output from the wind farms in South Australia averaged only around 14 MW during the high-priced TI.

In addition the constraint V>S_NIL_HYTX_HYTX limited flow to South Australia on the Heywood interconnector to around 426 MW during DI 1840 hrs. This constraint manages the post-contingent load on the remaining Heywood 275/500 kV transformer, on trip of the other transformer. The Murraylink interconnector has been on a scheduled outage since 15 May 2013 and could not provide additional imports.

The shape of the offer curve caused dispatch prices to increase from $199.99/MWh to over $11,090.79/MWh in consecutive DIs, due to changes in the demand and the export limits of the Heywood interconnector.

The dispatch price reduced to $51.34/MWh in the subsequent DI, due to around 100 MW of non-scheduled generation from Port Stanvac and Angaston PS coming on-line in response to the high dispatch price (the units can reach full capacity within one DI).

In addition 358 MW from was rebid from bands priced at $11,000/MWh and more, to-$1,000/MWh in the DI following the high price.

A 30-minute spot price of $90.80/MWh for TI 1900 hrs was forecast in the pre-dispatch schedule for TIs 1830 hrs.  The high spot price was not forecast as it was caused by rebids that were received after the pre-dispatch run.


Electricity Pricing Event Report – Wednesday 5 June 2013

Market Outcomes:  South Australia recorded a 30-minute spot price of $2,163.68/MWh for the trading interval (TI) ending 1800 hrs on Wednesday.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below.  

Detailed Analysis:  The 5-minute dispatch price reached $12,190.10/MWh for dispatch interval (DI) 1800 hrs.

A rebid received at 1736 hrs for the generation of Northern PS unit 1 moved 50 MW from bands priced at $90/MWh and less, to $12,194.44/MWh from DI ending 1745 hrs.

Quarantine PS unit 5 received a signal to synchronise for DI 1740 hrs, followed by a dispatch target of 66 MW for DI ending 1745 hrs. The unit had 80 MW of generation capacity offered at $298/MWh, and this offer set the 5-minute dispatch price for DI 1745 hrs. Origin Energy submitted a revised offer at 1743 hrs, rebidding the 80 MW to $12,190.10/MWh from DI ending 1750 hrs, and this offer set the price for the high-priced DI.

The rebidding occurred during the evening peak, when the South Australian demand increased from 1969 MW to 2052 MW during the TI ending 1800 hrs. The shape of the offer curve contributed to the price spike, as there was no generation offered in the $300/MWh - $11,000/MWh price bands. The demand increase of 83 MW caused dispatch prices to increase from $298/MWh to $12,190/MWh in consecutive DIs.

During the high-priced DI, the Heywood interconnector was exporting 460 MW to South Australia (its upper transfer limit). The Murraylink interconnector has been on a scheduled outage since 15 May 2013 and could not provide additional imports.

The dispatch price reduced to $58.20/MWh in the subsequent DI, due to around 100 MW of non-scheduled generation from Port Stanvac and Angaston PS coming on-line in response to the high dispatch price (the units can reach full capacity within one DI). In addition 96 MW of generation from two units at Dry Creek PS was rebid to -$1,000/MWh.These units required one DI to synchronise and received dispatch targets for 1800 hrs.

The $12,000/MWh spot price was not forecast in the 1730 hrs pre-dispatch schedule, as the rebids were received after the schedule was published. In addition Quarantine unit 5 was not scheduled for generation in the pre-dispatch schedule, as the South Australian demand for 1800 hrs was underestimated in pre-dispatch.


 

Electricity Pricing Event Report – Tuesday 4 June 2013 

Market Outcomes:  South Australian spot prices were around $1,900/MWh for the trading intervals (TIs) ending 1800 hrs to 1930 hrs on Tuesday. A further price spike of $1,890.44/MWh was recorded for TI ending 0000 hrs on Wednesday morning. 

FCAS prices and energy prices for the other NEM regions were not affected by this event. 

Further details are provided below. 

Detailed Analysis:  5-Minute dispatch prices reached  $12,194.44/MWh for dispatch interval (DI) 1800 hrs, and $11,048.00/MWh for DIs 1805 hrs, 1850 hrs, 1915 hrs and 2340 hrs. 

The high dispatch prices can mostly be attributed to the profile, and specifically the steepness, of the offer curve of South Australian generation capacity.  From 1800 hrs to 1930 hrs, an average of

  • 1481 MW of capacity was offered at less than $70/MWh,
  • 0 MW was offered at $300 - $11,000/MWh,
  • 405 MW was offered at more than $11,000/MWh. 

The South Australian demand was between 1911 MW and 2009 MW from 1800 hrs to 1930 hrs. The shape of the offer curve caused dispatch prices to increase from around $60/MWh to over $11,000/MWh in consecutive DIs, due to changes in the demand and the export limits of the Heywood interconnector. 

Exacerbating the situation was the low amount of wind generation available over the evening peak – the output from the wind farms in South Australia averaged only around 74 MW during the high-priced TIs. 

In addition the constraint V>S_NIL_HYTX_HYTX limited flow to South Australia on the Heywood interconnector to around 444 MW during the high-priced DIs. This constraint manages the post-contingent load on the remaining Heywood 275/500 kV transformer, on trip of the other transformer. The Murraylink interconnector has been on a scheduled outage since 15 May 2013 and could not provide additional imports. 

Every incidence of a high dispatch price resulted in a much lower dispatch price in the subsequent DI, due to around 100 MW of non-scheduled generation from Port Stanvac and Angaston PS coming on-line in response to the high dispatch price (the units can reach full capacity within one DI). The generation from these unscheduled units resulted in prices returning to around $58-$63/MWh for the DIs following the high prices. 

The only exception occurred for DIs 1800 hrs and 1805 hrs, when both DIs experienced high prices. The generation response of the non-scheduled units to the high 1800 hrs price could not fully offset the demand increase during the next 5 minutes (1800 hrs to 1805 hrs). An offer of $11,048.00/MWh from Quarantine PS was required to meet the demand at 1805 hrs. Prices reduced to $59.01/MWh from DI 1810 hrs when 71 MW from Quarantine PS was rebid to -$1,000/MWh, and Dry Creek unit 1 (fast start unit) was synchronised and started generating. 

The high spot price for TI 000 hrs on Wednesday morning was caused by the hot water load pickup of around 275 MW in 10 minutes (approximately 18% of the SA demand at the time). 

30-Minute spot prices of $11,048.00/MWh and $12,194.44/MWh were forecast in the pre-dispatch schedules for TIs 1800 to 1930 hrs.  The actual prices were lower at around $1,900/MWh due to the demand response from the non-scheduled units.

 


 

Electricity Pricing Event Report – Monday 3 June 2013 

Market Outcomes:  South Australian spot prices were around $2,000/MWh for 12 trading intervals (TIs) in the period 0730 hrs to 1930 hrs on Monday. A further price spike of $1,889.86/MWh was recorded for TI ending 0000 hrs on Tuesday morning.

FCAS prices and energy prices for the other NEM regions were not affected by this event.

Further details are provided below. 

Detailed Analysis:  5-Minute dispatch prices were between $11,048.00/MWh and $12,899.60/MWh for a number of dispatch intervals (DIs) during the day, with the first price spike occurring for DI 0720 hrs. 

The Osborne GTs with a registered capacity of 180 MW tripped on Friday, 31 May 2013. Three Torrens Island B units with registered capacity of 600 MW in total tripped shortly after. The Osborne GTs were synchronised at 1626 hrs and reached full capacity (188 MW) from DI ending 1910 hrs. Torrens Island B2 was synchronised at 1020 hrs on Monday, but due to a very slow ramp up rate the unit only reached its full capacity of 200 MW from DI 1710 hrs. Torrens Island units B1 and B3 remain out of service until further notice. Torrens Island A4 was bid as unavailable from 1305 hrs on the day due to a technical issue with the unit. 

Exacerbating the situation was the negligible amount of wind generation available on the day – from 0730 hrs to 1930 hrs, the output from the wind farms in South Australia averaged only around 22 MW. 

In addition the constraint V>S_NIL_HYTX_HYTX limited flow to South Australia on the Heywood interconnector to around 415 MW during the high-priced TIs. This constraint manages the post-contingent load on the remaining Heywood 275/500 kV transformer, on trip of the other transformer. The Murraylink interconnector has been on a scheduled outage since 15 May 2013 and could not provide additional imports. 

The $11,000/MWh - $12,900/MWh dispatch prices can mostly be attributed to the profile, and specifically the steepness, of the offer curve of South Australian generation capacity. From 0720 hrs onwards, an average of

  • 1270 MW of capacity was offered at less than $70/MWh,
  • 50 MW of capacity offered at $70 - $300/MWh
  • 0 MW was offered at $300 - $11,000/MWh (a few DIs had 10-35 MW in this band),
  • 400 MW was offered at more than $11,000/MWh. 

The South Australian demand was between 1574 MW and 1916 MW during the high priced TIs. Small changes in the demand, wind generation and the export limits of the Heywood interconnector caused dispatch prices to increase from around $60/MWh to over $11,000/MWh in consecutive DIs. 

Every incidence of a high dispatch price resulted in a much lower dispatch price in the subsequent DI, due to around 110 MW of non-scheduled generation from Port Stanvac and Angaston PS coming on-line in response to the high dispatch price (the Angaston units can reach full capacity of 50 MW in one DI). The generation from these non-scheduled units resulted in prices returning to around $55-$65/MWh for most DIs following the high prices.