Electricity Report
21 to 27 July 2013
Introduction
The AER is required to publish the reasons for significant variations between forecast and actual price and
is responsible for monitoring activity and behaviour in the National Electricity Market. The Electricity Report
forms an important part of this work. The report contains information on significant price variations,
movements in the contract market, together with analysis of spot market outcomes and rebidding behaviour.
By monitoring activity in these markets, the AER is able to keep up to date with market conditions and
identify compliance issues.
Weekly spotlight
In addition to monitoring outcomes in the NEM on a weekly basis, the AER also monitors long term trends
in the energy sector. The AER’s website brings together many of the statistics, tables, and data from AER
publications such as the State of the Energy Market report.
One of the trends we monitor is the level of peak demand, which has been the subject of interest in the
electricity sector over the last eighteen months. The spotlight figure below details seasonal peak demand
across the NEM for both the winter and summer periods since the NEM began.
Spotlight figure: Seasonal peak demand (NEM)
© Commonwealth of Australia
AER reference: 39220 – D13/111560
40
Gigawatts
35
30
25
20
2013 (YTD)
2012/13
2012
2011/12
2011
2010/11
2010
2009/10
2009
2008/09
2008
2007/08
2007
2006/07
2006
2005/06
2005
2004/05
2004
2003/04
2003
2002/03
2002
2001/02
2001
2000/01
2000
1999/00
1999
1998/99
Summer
Winter
Note: Tasmania joined the NEM in May 2005.
The figure shows a steady increase in peak demand for both winter and summer from 1998 up to around
2009. From 2009, peak demand remained steady before trending downwards in recent years. Winter peak
demand in 2012, for example, was the lowest since 2004.
More statistics can be found in the performance of the energy sector section of our website.
Spot market prices
Figure 1 shows the volume weighted average (VWA) prices for the current week (with prices shown in
Table 1) and the preceding 12 weeks, as well as the VWA price over the previous 3 financial years.
2
Figure 1: Volume weighted average spot price by region ($/MWh)
250
$/MWh
200
150
100
50
0
Current week
Tas
Previous week
7 Jul
30 Jun
SA
23 Jun
16 Jun
Vic
9 Jun
NSW
2 Jun
26 May
19 May
12 May
5 May
28 Apr
12/13 FY
11/12 FY
10/11 FY
Qld
Table 1: Volume weighted average spot prices by region ($/MWh)
Region
Qld
NSW
Vic
SA
Tas
Current week
71
62
63
78
50
12-13 financial YTD
65
68
77
83
61
13-14 financial YTD
62
59
60
72
52
Longer-term statistics tracking average spot market prices are available on the AER website.
Spot market price forecast variations
The AER is required under the National Electricity Rules to determine whether there is a significant variation
between the forecast spot price published by the Australian Energy Market Operator (AEMO) and the actual
spot price and, if there is a variation, state why the AER considers the significant price variation occurred. It
is not unusual for there to be significant variations as demand forecasts vary and participants react to
changing market conditions. A key focus is whether the actual price differs significantly from the forecast
price either four or 12 hours ahead. These timeframes have been chosen as indicative of the time frames
within which different technology types may be able to commit (intermediate plant within four hours and
slow start plant within 12 hours).
There were 113 trading intervals throughout the week where actual prices varied significantly from forecasts.
This compares to the weekly average in 2012 of 60 counts and the average in 2011 of 78. Reasons for the
3
variations for this week are summarised in Table 2. Based on AER analysis, the table summarises (as a
percentage) the number of times when the actual price differs significantly from the forecast price four or 12
hours ahead and the major reason for that variation. The reasons are classified as availability (which means
that there is a change in the total quantity or price offered for generation), demand forecast inaccuracy,
changes to network capability or as a combination of factors (when there is not one dominant reason). An
instance where both four and 12 hour ahead forecasts differ significantly from the actual price will be
counted as two variations.
Table 2: Reasons for variations between forecast and actual prices
Reason for variation
Availability
Demand
Network
Combination
% of total above forecast
2
6
0
2
% of total below forecast
22
45
0
23
Note: Due to rounding, the total may not be exactly 100 per cent
Generation and bidding patterns
The AER reviews generator bidding as part of its market monitoring to better understand the drivers behind
price variations. Figures 2 to 6 show, the total generation dispatched and the amounts of capacity offered
within certain price bands for each 30 minute trading interval in each region.
4
Figure 2: Queensland generation and bidding patterns
12000
10000
MW
8000
6000
4000
2000
0
12 noon - 27 Jul
5
12 noon - 26 Jul
$0/MWh to $50/MWh
$500/MWh to $5000/MWh
12 noon - 25 Jul
12 noon - 24 Jul
12 noon - 23 Jul
12 noon - 22 Jul
12 noon - 21 Jul
<$0/MWh
$100/MWh to $500/MWh
Total generation (MW)
$50/MWh to $100/MWh
Above $5000/MWh
Figure 3: New South Wales generation and bidding patterns
16000
14000
12000
MW
10000
8000
6000
4000
2000
0
12 noon - 27 Jul
6
12 noon - 26 Jul
$0/MWh to $50/MWh
$500/MWh to $5000/MWh
12 noon - 25 Jul
12 noon - 24 Jul
12 noon - 23 Jul
12 noon - 22 Jul
12 noon - 21 Jul
<$0/MWh
$100/MWh to $500/MWh
Total generation (MW)
$50/MWh to $100/MWh
Above $5000/MWh
Figure 4: Victoria generation and bidding patterns
12000
10000
MW
8000
6000
4000
2000
0
$50/MWh to $100/MWh
Above $5000/MWh
12 noon - 27 Jul
7
12 noon - 26 Jul
$0/MWh to $50/MWh
$500/MWh to $5000/MWh
12 noon - 25 Jul
12 noon - 24 Jul
12 noon - 23 Jul
12 noon - 22 Jul
12 noon - 21 Jul
<$0/MWh
$100/MWh to $500/MWh
Total generation (MW)
Figure 5: South Australia generation and bidding patterns
3000
2500
MW
2000
1500
1000
500
0
12 noon - 27 Jul
$0/MWh to $50/MWh
$500/MWh to $5000/MWh
12 noon - 26 Jul
12 noon - 25 Jul
12 noon - 24 Jul
12 noon - 23 Jul
12 noon - 22 Jul
12 noon - 21 Jul
<$0/MWh
$100/MWh to $500/MWh
Total generation (MW)
$50/MWh to $100/MWh
Above $5000/MWh
Figure 6: Tasmania generation and bidding patterns
3000
2500
MW
2000
1500
1000
500
0
12 noon - 27 Jul
8
12 noon - 26 Jul
$0/MWh to $50/MWh
$500/MWh to $5000/MWh
12 noon - 25 Jul
12 noon - 24 Jul
12 noon - 23 Jul
12 noon - 22 Jul
12 noon - 21 Jul
<$0/MWh
$100/MWh to $500/MWh
Total generation (MW)
$50/MWh to $100/MWh
Above $5000/MWh
Frequency control ancillary services markets
Frequency control ancillary services (FCAS) are required to maintain the frequency of the power system
within the frequency operating standards. Raise and lower regulation services are used to address small
fluctuations in frequency, while raise and lower contingency services are used to address larger frequency
deviations. There are six contingency services:

fast services, which arrest a frequency deviation within the first 6 seconds of a contingent event (raise
and lower 6 second)

slow services, which stabilise frequency deviations within 60 seconds of the event (raise and lower
60 second)

delayed services, which return the frequency to the normal operating band within 5 minutes (raise and
lower 5 minute) at which time the five minute dispatch process will take effect.
The Electricity Rules stipulate that generators pay for raise contingency services and customers pay for
lower contingency services. Regulation services are paid for on a “causer pays” basis determined every four
weeks by AEMO.
The total cost of FCAS on the mainland for the week was $276 000 or less than 1 per cent of energy
turnover on the mainland. In Tasmania (which requires dedicated services for much of the time) the total
cost for the week was $57 500 or less than one per cent of energy turnover in Tasmania.
Figure 7 shows the daily breakdown of costs for each service, as well as the average daily costs for the
previous financial year.
9
Figure 7: Daily frequency control ancillary service cost
80 000
60 000
$
40 000
20 000
0
27 Jul
Raise 5min
Lower 5min
26 Jul
25 Jul
Raise 60sec
Lower 60sec
24 Jul
23 Jul
22 Jul
21 Jul
Average cost
Raise 6sec
Lower 6sec
Raise Reg
Lower Reg
Detailed market analysis of significant price events
We provide more detailed analysis of events where the spot price was greater than three times the weekly
average price in a region and above $250/MWh or was below -$100/MWh.
There was one such occasion during this week, which occurred in Queensland on Wednesday 24 July. The
table below shows the actual Queensland price, demand and available capacity outcomes compared to
those forecast 4 and 12 hour ahead.
Table 3: Queensland, Wednesday 24 July
6:30 AM
Actual
4 hr forecast
12 hr forecast
Price ($/MWh)
2243.81
56.12
66.21
Demand (MW)
5750
5680
5709
10
Available capacity (MW)
9601
9489
9659
Conditions at the time saw demand 70 MW and available capacity 112 MW greater than that forecast four
hours ahead. At 6.08 am, effective at 6.10 am, CS Energy rebid 120 MW at Gladstone from prices below
$55/MWh to above $12 700/MWh. The reason given was “Portfolio rearrangement due to-cb2 return–SL”.
Over two rebids at 6.02 am and 6.17 am, effective from 6.10 am and 6.25 am respectively, CS Energy
reduced the availability of Kogan Creek by a total of 138 MW. All of this capacity was priced below
$40/MWh. This saw Kogan Creek output decreased from around 720 MW at 6.05 am to 587 MW at
6.25 am. The reasons given were “Testing –F/F out of service – SL” and “Technical issues –runback due
to F/F issue – SL”. These rebids were only effective for the 6.30 am trading interval.
At 6.30 am demand in Queensland increased by 164 MW (from 5828 MW at 6.25 am to 5992 MW at
6.30 am), while the export limit on QNI reduced by 78 MW into Queensland (from 330 MW to 258 MW).
The reduction in limit occurred when a constraint used to manage voltage stability on the loss of Kogan
Creek bound.
Generators with low priced capacity were either ramp rate limited or limited by their fast start inflexibility
profile, hence higher priced generation was dispatched, setting the price at $13 005/MWh at 6.30 am. By
6.35 am, with some generators no longer ramp rate limited and a step increase in low price capacity
available at Kogan Creek, prices reduced to below $76/MWh.
There was no other significant rebidding.
11
Financial markets
Figure 8 shows for all mainland regions the prices for base contracts (and total traded quantities for the
week) for each quarter for the next four financial years.
120
900
100
750
80
600
60
450
40
300
20
150
0
Number of contracts traded
$/MWh
Figure 8: Quarterly base future prices Q3 2013 – Q2 2017
0
Q2 2017
Q1 2017
Q4 2016
Vic volume
Vic
Q3 2016
Q2 2016
Q1 2016
NSW volume
NSW
Q4 2015
Q3 2015
Q2 2015
Q1 2015
Q4 2014
Q3 2014
Q2 2014
Q1 2014
Q4 2013
Q3 2013
Qld volume
Qld
SA volume
SA
Source: ASXEnergy.com.au
Figure 9 shows how the price for each regional Quarter 1 2014 base contract has changed over the last 10
weeks (as well as the total number of trades each week). The closing Quarter 1 2012 and Quarter 1 2013
prices are also shown.
12
120
600
100
500
80
400
60
300
40
200
20
100
0
Number of contracts traded
$/MWh
Figure 9: Price of Q1 2014 base contracts over the past 10 weeks (and the past 2 years)
0
Current
14 Jul
Vic volume
Vic
07 Jul
30 Jun
NSW volume
NSW
23 Jun
16 Jun
09 Jun
02 Jun
26 May
19 May
Q1 2013
Q1 2012
Qld volume
Qld
SA volume
SA
Note: Base contract prices are shown for each of the current week and the previous 9 weeks, with average prices shown for yearly
periods 1 and 2 years prior to the current year
Source: ASXEnergy.com.au
Prices of other financial products (including longer-term price trends) are available in the Performance of
the Energy Sector section of our website.
Figure 10 shows how the price for each regional Quarter 1 2014 cap contract has changed over the last 10
weeks (as well as the total number of trades each week). The closing Quarter 1 2012 and Quarter 1 2013
prices are also shown. The cap contracts limit exposure to extreme spot prices (above $300/MWh) and is
an indicator of the cost of risk management.
13
25
150
20
120
15
90
10
60
5
30
0
0
14
SA volume
SA
Current
August 2013
14 Jul
Australian Energy Regulator
Vic volume
Vic
07 Jul
Source: ASXEnergy.com.au
30 Jun
NSW volume
NSW
23 Jun
16 Jun
09 Jun
02 Jun
26 May
19 May
Q1 2013
Q1 2012
Qld volume
Qld
Number of contracts traded
$/MWh
Figure 10: Price of Q1 2014 cap contracts over the past 10 weeks (and the past 2 years)