Significant price variation report

Appendix A – AER SPV reporting thresholds

The Significant Price Variation Reporting thresholds are set out below.

The two reporting thresholds set out in the Victorian SPV guideline are when:

the trade weighted market price published by AEMO on a gas day is more than three times the average price for the previous 30 days and the trade weighted market price is equal to or greater than $15/GJ

the ancillary payment amount published by AEMO on a gas day is an amount payable or receivable which exceeds $250 000.

The five reporting thresholds set out in the STTM SPV guideline are:

variations greater than $7/GJ between the D-2 price and ex ante price

variations greater than $7/GJ between the ex ante and the ex post price

the ex ante price being greater than three times the 30 day rolling average price and greater than $15/GJ

the ex post price being greater than three times the 30 day rolling average price and greater than $15/GJ

MOS service payments exceeds $250 000.

Appendix B – Price impact analysis methodology for SPV days

Short term trading market

Throughout this report, we have focussed our analysis on participant driven supply and demand factors that contributed to the significant price variation (SPV).

Supply is represented by offers submitted to AEMO. If a participant intends to supply gas to a hub on a particular gas day, they must submit an offer to AEMO which sets out their identity, the hub (for example, the Adelaide hub), the facility (for example, a particular pipeline or storage facility), the prices and quantities offered in each price step.

The National Gas Rules (NGR) state offers are confidential information until the end of the gas day to which they relate.⁵⁶

On any given gas day, total demand is made up of:

• 
  uninterruptable (or uncontrollable) demand
  
• 
  controllable (or price sensitive/interruptible) demand
  

An example of uninterruptable demand is residential consumption.⁵⁷ Each participant submits a price taker bid which represents its forecast of uninterruptable demand.

An example of price sensitive demand could be an industrial user that is prepared to purchase gas but only at (or below) a particular price. This type of consumption is reflected in price specific bids (this report refers to them as simply ‘bids’).⁵⁸

The NGR states that price taker bids are confidential information.⁵⁹

To avoid the disclosure of confidential information, this report does not state any individual price taker bids. At times, the change in a particular participant’s price taker bid will be noted. At times it is necessary to report on a participant’s change in price taker bid so we can consider this alongside any other changes made to bids and offers in order to understand the participant’s overall impact on the market. Excluding the change in price taker bids could result in an inaccurate representation of the drivers behind a particular price outcome.

Our approach is the same regardless of whether the SPV represents a rise, or fall, in price.

In general, a participant could contribute to a price rise by:

• 
  increasing their demand (either uninterruptable or controllable)
  
• 
  reducing their quantity of lower priced offers
  

Conversely, a participant could contribute to a price fall by:

• 
  decreasing their demand (either uninterruptable or controllable)
  
• 
  increasing their quantity of lower priced offers
  

When analysing an SPV between the D-2 and the D-1 schedules, we have considered changes made by participants to price taker bids, bids priced at or above the D-1 price, and offers priced at or below the D-1 price.

This allows us to measure the overall market impact arising from a particular participant’s change in bids and/or offers from the D-2 to the D-1 schedules.

If a participant’s change results in their net position in the hub changing significantly in a way that could have contributed to the SPV, then it is likely to feature in this report.

1^ The obligation is set out in the National Gas Rules. Rule 498(3)(b) relates to SPVs in the Short Term Trading Markets, and rule 355(1)(b) relates to SPVs in the Victorian market.

2^ These thresholds are noted in Appendix A.

3^ The June SPV report is available here: http://www.aer.gov.au/wholesale-markets/market-performance/significant-price-variation-report-june-2016

4^ We note had it not been for a long term LNG contract, the investment to extend the Moomba field would not have happened.

5^ Some industrial participants, for example Qenos or AB Cement participate directly in the market. Others have another party – usually an energy retailer – participate on their behalf.

6^ Unlike the Victorian gas market, where many gas fired electricity generators (GFG) sit within the physical boundaries of the market, no GFG sits within the physical boundaries of the Adelaide or Sydney STTM and therefore do not have to participate in the market. However, these GFGs can make offers to buy gas from the daily market for transport to their power station (withdrawal bids). Though more commonly they choose to bypass markets and buy gas directly under long term contracts.

7^ In 2020, domestic demand (residential and commercial, industrial, and gas fired electricity generators) is forecast to be around 515 PJ a year, whereas the demand from LNG is forecast to reach nearly 2000 PJ.

8^ Also, the EGP has been connected to the Wilton connection point in New South Wales. Previously only the MSP was connected to this point. The new connection enables Sydney’s demand to be supplied predominately by the EGP (which sources gas from Victoria) if required by participants.

9^ It is noted that gas-fired generation decreased in Queensland and the AER understands this is because the ramp gas that made gas-fired generation cheap in previous winters was no longer available in 2016.

10^ See AER Communication Winter Energy Prices, http://www.aer.gov.au/communication/winter-energy-prices-2016.

11^ These factors were also discussed in the ACCC Gas Inquiry Report April 2016: http://www.accc.gov.au/regulated-infrastructure/energy/east-coast-gas-inquiry-2015

12^ We calculated the top ten demand days across winter 2015 and 2016. Seven of the ten days high demand days occurred in 2015. The high demand days in 2015 ranged from around 1.56–1.63 PJ.

13^ The historic dynamic has been that producers and LNG exporters have not participated in the traded markets. Trading of gas through the STTMs and Victorian Gas Market has been limited to smaller balancing volumes between gas retailers topping up long term supply contracts or to accommodate short term changes in demand.

14^ See section 4.4.5 of the ACCC Gas Inquiry Report April 2016, www.accc.gov.au

15^ South Australia, New South Wales, and Victoria.

16^ Source: Bulletin Board data; INT911, INT924, INT925, www.gasbb.com.au. Using capacities of 1,024 TJ for winter 2016 and 1,010 TJ for winter 2015.

17^ In August, Lochard Energy (the owner/operator of Iona) informed the AER that Iona’s recent storage is at historic lows.

18^ Date range: 13 June 2016 to 31 July 2016. Data source: ex ante scheduled quantity (INT652).

19^ http://www.afr.com/business/energy/gas/shell-australia-juggles-gas-sales-amid-pricing-swings-20160829-gr45uk

The Chairman was quoted as saying Shell had sold twice as much gas into the domestic market than it had purchased from third parties from its operation

20^ Visibility of gas traded at Wallumbilla is limited to trades on the Exchange, with market intelligence indicating that a smaller portion of Queensland gas is traded through the Exchange, than gas traded off-market, bilaterally.

21^ This is based on estimates of gas consumption by South Australian generators for winter 2015 (137.7 TJ/d) and winter 2016 (174.1 TJ/d). The total change in GFG requirements illustrated in Figure  is around 3.2 gigawatt hours per day, comparing 2015 (13.1 GWh/d) and 2016 (16.3 GWh/d).

22^ Liquid = diesel. There are some small peaking plants in South Australia that are powered by diesel. These units make up a small proportion of South Australia’s overall generation capacity, and only run in response to high prices.

23^ https://www.agl.com.au/about-agl/media-centre/article-list/2016/july/agl-update-on-fy17-gas-portfolio-margins

24^ The majority of this quantity (2 TJ) was delivered on the EGP.

25^ This contributed around $41 297 of additional cost for the balancing gas services (compared to the cost for net decrease requirements being allocated entirely on the MSP). The 24.48 TJ net decrease requirement (22.15 TJ over forecast plus 2.34 TJ over supply) was also impacted by MOS deliveries on the EGP balancing under forecasting in the Wollongong sub-network (4.35 TJ). Collectively, these quantities account for the total MOS requirement (24.5 TJ supply/demand error, 4.35 TJ of increase EGP MOS and counteracting 4.35 TJ of additional MOS decrease allocations on the MSP: 33.2 TJ of MOS allocations in total).

26^ For the D-2 schedule, price taker bids (which reflect uninterruptable demand) were around 70.5 TJ. For the D-1 schedule, they were 71.7 TJ (1.2 TJ higher).

27^ The previous record D-1 price was $18.99/GJ for the 24 June 2016 gas day which is assessed in our June report. Before this, the previous record D-1 price was $14.89/GJ for the 4 July 2012 gas day.

28^ The similar levels of demand can be seen in Figure , where the solid red line and the dotted red line are closely correlated.

29^ For the D-2 schedule, price taker bids totalled 321 TJ. For the D-1 schedule, price taker bids totalled 317 TJ.

30^ Santos Direct offered a total of 25 TJ for the D-1 schedule. 12.5 TJ of this was priced at $10.75/GJ, 6.25 TJ was priced at $13.80/GJ, and the remaining 6.25 TJ was priced at $15.60/GJ. Santos had no offers for the D-2 schedule.

31^ For the D-2 schedule, price taker bids totalled 93.2 TJ. For the D-1 schedule, price taker bids totalled 95.31 TJ.

32^ This is a net amount. AGL increased offers on the MAP by 6 TJ, and reduced offers on SEAGas by 19.2 TJ.

33^ This is the highest Victorian price since 2007-2008 (the price previously reached $54.88/GJ on 22 November 2008).

34^ While this wasn’t the lowest temperature this winter, the wind chill had a more significant effect which led to overnight temperatures plummeting and snow in a number of areas across the state. Actual demand exceeded 1200 TJ, the highest level this winter.

35^ This hourly profiling had no impact on prices, as prices are set on the daily injection quantity.

36^ It is likely this was to supply gas to Hallett; its gas-fired electricity generator located around 210 km north of Adelaide.

37^ 4 TJ – 3.5 TJ = 500 GJ

38^ The reduced demand was a result controllable demand, namely EnergyAustralia reducing its backhaul bids on the MAP priced at or above $20.22/GJ by 7.5 TJ. By itself, this rebid resulted in less demand at the Adelaide hub, and therefore did not apply upwards pressure on the D-1 price.

39^ AGL reduced offers on the MAP by 4.3 TJ, and reduced offers on SEAGas by 4.7 TJ.

40^ This is a net amount. Simply Energy increased offers on the MAP by 3.5 TJ, and reduced offers on SEAGas by 9 TJ.

41^ This is a net amount. EnergyAustralia increased offers on the MAP by 10.5 TJ, and reduced offers on SEAGas by 18.5 TJ. When considered alongside its 7.5 TJ reduction in bids, the broader net impact still applied upwards pressure on prices; however the net quantity of gas was only 500 GJ.

42^ For the D-2 schedule, Stanwell had no offers at any price. For the D-1 schedule, it made a 10 TJ offer priced at $7.10/GJ, and a 5 TJ offer priced at $12/GJ.

43^ Alinta also increased its offers priced above $7.10/GJ for the D-1 schedule by 15.4 TJ.

44^ 17.225 TJ of gas was purchased by a number of participants at prices between $5.55/GJ - $6.20/GJ in balance-of-day product trades.

45^ Analysis indicates the renomination of flows reduced the scheduled delivery quantity into flow controlled delivery points on the EGP and did not contribute to additional counteracting MOS requirements on the day.

46^ A pipelines ability to offer decrease MOS is limited by the amount of gas it is providing to the hub. For example, if a pipeline was providing 50 TJ to a hub, it could provide up to 50 TJ in decrease MOS. There is no such limitation for the provision of increase MOS.

47^ For further details about MOS, please refer to the significant price variation report for January 2016 (https://www.aer.gov.au/wholesale-markets/market-performance/significant-price-variation-report-13-and-23-january-2016-sydney-sttm).

48^ CMOS is defined for this report’s purposes as the need for simultaneously increase MOS (increased flows) to be provided by one pipeline at the same time as decrease MOS (parked gas) by the other pipeline on the same day in the magnitude of more than 2 TJs on both pipelines.

49^ While the EGP is also connected at Wilton, it is connected by a flow controlled point.

50^ Gas can flow into the Wollongong sub network through the Mount Keira pressure reduction station. However gas can only flow in this direction and cannot flow back towards the northern Sydney network.

51^ The numbers of counteracting MOS days in June were the same in 2015 and 2016, with a lower quantity of counteracting MOS allocated across June 2016.

52^ Absolute MOS allocations of 1.5 TJ of increase MOS on the EGP, offset by an equivalent 1.5 TJ of decrease MOS on the MSP.

53^ The difference between the nominated EGP deliveries through the flow controlled CTPs into Wollongong (the dotted black line in Figure ) and the actual metered flows at those points (the delivered quantities shaded red) is the quantity of MOS allocated on the pipeline over the period.

54^ Total MOS service costs were $94 431 higher in 2016: $156 958 in 2016 ($83 107 in June and $74 851 in July) compared to $62 527 in 2015 ($34 172 in June and $28 355 in July).

55^ https://www.aemo.com.au/Gas/National-planning-and-forecasting/Victorian-Gas-Planning-Report

56^ Rule 407(4)

57^ This is because household gas consumption is unlikely to be influenced by the market price on any given gas day.

58^ These are sometimes referred to as ‘ex ante bids’ or ‘price sensitive bids’.

59^ Rule 409(4)

Significant price variation report East Coast Gas Markets June 2016