1. Intervention pricing working group
MEETING 2:
20 DECEMBER AM – 1 PM AEDT

2. Agenda ACTION ITEMS FROM LAST IPWG MEETING
FUNDAMENTALS OF INTERVENTION PRICING
09 FEB 2017 DIRECTION EVENT – BACKGROUND & OUTCOMES
09 FEB 2017 DIRECTION EVENT – ANALYSIS OF ALTERNATIVE OPTIONS
MATTERS TO CONSIDER
OTHER TOPICS FOR DISCUSSION

3. ACTION ITEMS FROM ipwg MEETING on 20 November
ACTION ITEM 1: AEMO to advise why there are no levels below 1200 MW for system strength requirements
Covered in AEMO’s report on SA system strength assessment:
ACTION ITEM 2: AEMO to confirm why system strength directions are classified as ‘Energy’ Directions and not ‘Other’ Directions.
A direction must be either an “energy” direction (NER ) or an “other” direction (NER A)
NER A(a1) precludes system strength directions being “other” directions
System strength directions must therefore be “energy” directions
ACTION ITEMS 3 and 4:
AEMO to provide a detailed analysis of the 09 Feb 2017 Direction event
Formulation of feedback constraint equations
Effectiveness of counteractions
AEMO to present findings from pre-dispatch constraint formulation approach
Covered in sessions 4 and 5
ACTION ITEM 5: Attendees to provide feedback on compensation issues

4. INTERVENTION PRICING INPUTS, outputs & ASSUMPTIONS
FUNDAMENTALS:
INTERVENTION PRICING INPUTS, outputs & ASSUMPTIONS
Intervention & Counter-action
constraints
Dispatch Generator & IC targets
Price bids
Dispatch (Outturn) run
Dispatch prices
Network, System security and FCAS constraints
Intervention = 1 run
Fast-start profiles
Intervention Pricing (What-If pricing) run
What-If Generator & IC targets
SCADA inputs (line flows, transformer loadings)
What-If prices
Intervention = 0 run
Intervention Pricing constraints
ONLY What-If Pricing constraints invoked (Intervention & Counter-action constraints removed).
Intervention Pricing run assumptions:
[InitialMWDI n = TotalClearedDI n-1] Generators & ICs
[CurrentModeDI n = FSTargetModeDI n-1] Fast-start generators

5. COUNTER-ACTION Counter-action* is applied in the order of:
Scheduled unit within the same region and in the same portfolio as Directed plant
Scheduled unit within the same region and outside the portfolio of the Directed plant
Additional points:
No counter-action applied to semi-scheduled plant due to intermittent output
Counter-action only applied to scheduled units with: Target > min. load
In SA, counter-action only applied to units with:
Target > min. load + 50 MW (threshold)
* NER 4.8.9(b)(1) requires AEMO to use reasonable endeavours to minimise cost and compensation to directed and affected participants as a result of a direction.

6. 09 FEBRUARY 2017 direction event - background
Adelaide temperature reached 39.4 degrees at 1700 hrs.
Operational Demand = 3,041 MW
Forecast LOR2 condition in SA between 1600 hrs and 1800 hrs on 09 Feb
Insufficient market response
Latest time to Intervene – 1500 hrs.
DI 1720 hrs used for case study in the remaining slides.

7. 09 FEBRUARY 2017 direction event - background:
Intervention, COUNTER-ACTION & pricing constraints
DI = 1720 hrs:
Dispatch run (Intervention constraints and counter-action constraints):
#PPCCGT_O_E = 320 (CVP=55) Binds in the Dispatch run
#PPCCGT_E <= 214 (CVP=50) Violates in the Dispatch run
#MINTARO_C_E <= 30 (CVP = 48) Binds in the Dispatch run
#DRYCGT1_C_E <= 5 (CVP=48) Binds in the Dispatch run
#DRYCGT3_C_E <= 5 (CVP=48) Binds in the Dispatch run
Intervention pricing run (What-if Pricing constraints):
#PPCCGT_E <= 214 (CVP=50) Binds in the Pricing run
Increase in generation from PPCCGT due to Direction
= 320 – 214 = 106 MW
Decrease in generation from Mintaro + Dry Creek due to Counter-action
= 39 MW (Mintaro) + 65 MW (Dry Creek) = 104 MW

8. 09 FEBRUARY 2017 direction event - outcomes:
Interconnector target flows
VIC-NSW and Murraylink:

9. 09 FEBRUARY 2017 direction event - outcomes:
Interconnector TARGET flows
Heywood and QNI:

10. 09 FEBRUARY 2017 direction event - outcomes:
WHAT-IF PRICES for di 1720 hrs
Region
What-If prices
NSW
$13,458
QLD
$11,639 SA
$14,000
TAS
$40.05
VIC
$92.05
What caused the restricted flow across VIC-NSW interconnector (and consequently high prices in NSW and QLD)?
Constraint Equation
Constraint Description
Interconnectors on LHS
V>>SML_NIL_8
Avoid overload of Ballarat to Bendigo 220 kV line (flow North) for loss of Shepparton to Bendigo 220 kV line
Murraylink (co-efft = +1.0)
VIC-NSW (co-efft = +0.08)

11. <= LHS formulation: RHS formulation:
09 FEBRUARY 2017 DIRECTION EVENT - OUTCOMES:
Constraint formulation & inputs: V>>SML_NIL_8
LHS formulation:
x Broken Hill
x Murray Hydro
x Ararat wind farm
+ 1.0 x Flow on Murraylink IC
x Flow on VIC-NSW IC
RHS formulation:
3.017 X
[ Ballarat – Bendigo 220 kV line 15m rating
- MVA Flow on Ballarat – Bendigo 220 kV line
X MVA Flow on Shepparton – Fosterville
220 kV line
- 15 ]
x MW flow on VIC-NSW IC
X Broken Hill Solar farm
x Ararat Wind farm
+ 1.0 x MW flow on Murraylink IC
x Murray Output
+ [ If MW flow on Murraylink IC <= 0
then 0
Else (Murraylink VFRB Scheme A enablement status)
x (Murraylink VFRB Scheme B enablement status)
x MW flow on Murraylink IC ]
<=
Source of constraint input in the Intervention Pricing run:
MVA flows  same values as Dispatch run, SCADA inputs
MW flow on ICs, Generator outputs  Targets from previous interval

12. <= 09 FEBRUARY 2017 DIRECTION EVENT - OUTCOMES:
ACTUAL rhs inputs for di 1720 hrs
LHS formulation:
x Broken Hill (23.97)
x Murray Hydro (530)
x Ararat wind farm (113.49)
+ 1.0 x Flow on Murraylink IC (-185)
x Flow on VIC-NSW IC (-23)
RHS formulation:
3.017 X
[ Ballarat – Bendigo 220 kV line 15m rating ( )
MVA Flow on Ballarat – Bendigo 220 kV line (238.96)
X MVA Flow on Shepparton – Fosterville
220 kV line (106.35)
- 15 ]
- (226.98)
<=
Binding constraint
Marginal value = -162,271.43
-255
-255

13. 09 FEBRUARY 2017 DIRECTION EVENT – issue & POTENTIAL SOLUTIONS
Lack of simulated line flows in the Intervention Pricing run causes feedback constraint equations to incorrectly bind
Frequency:
Infrequent
09 Feb 2017 is the only event AEMO is aware of.
Potential Solutions:
Do Nothing
Power Flow Simulator: Using a power flow simulator, determine simulated line loadings consistent with generator targets in What-If pricing run
3. PD formulation approach: Replace DS formulation of feedback constraints with their PD formulation
PD formulation determines limits without usage of real-time inputs for line loadings.

14. <= LHS formulation: RHS formulation: Non-binding constraint
09 FEBRUARY 2017 DIRECTION EVENT – ANALYSIS OF POTENTIAL SOLUTIONS
SIMULATED rhs inputs for di 1720 hrs
LHS formulation:
x Broken Hill (23.97)
x Murray Hydro (530)
x Ararat wind farm (113.49)
+ 1.0 x Flow on Murraylink IC (-58.5)
x Flow on VIC-NSW IC (148)
RHS formulation:
3.017 X
[ Ballarat – Bendigo 220 kV line 15m rating ( )
- MVA Flow on Ballarat – Bendigo 220 kV line (161)
X MVA Flow on Fosterville – Shepparton kV line (136)
- 15 ]
- (226.98)
<=
Non-binding constraint
Marginal value = 0
-93.23

15. 09 FEBRUARY 2017 DIRECTION EVENT – ANALYSIS OF POTENTIAL SOLUTIONS:
PRICE AND Ic OUTCOMES BASED ON SIMULATED inputs for di 1720 hrs
Region
What-If price using simulated line loadings
What-If price using DS formulation
NSW
$179.26
$13,457.81
QLD
$159.87
$11,639.00 SA
$175.28
$14,000
TAS
$90.18
$40.05
VIC
$148.81
$92.05
Interconnector
What-If target flow with simulated line loadings
What-If target flow with DS formulation
Actual target flow in Dispatch run
VIC-NSW
148 MW
-23 MW
589 MW
Murraylink
-58 MW
-185 MW
-83 MW
VIC-SA
500 MW
600 MW
QNI
-904 MW
-1,048 MW
-700 MW
Terranora
-105 MW
-115 MW
-81 MW
Basslink
521 MW
529 MW

16. 09 FEBRUARY 2017 DIRECTION EVENT –ANALYSIS OF POTENTIAL SOLUTIONS
PD formulation approach:
AEMO (and consultants) performed a feasibility study to assess accuracy of this approach.
30 sample days were chosen based on: Price Level, Price Volatility, Price separation, Intervention and Demand.
Feasibility study involved:
Replacing the DS formulation of all feedback constraint equations with their PD formulation in the Dispatch files.
Use actual sub-region load values and wind generator outputs as inputs to PD RHS terms.
Re-run the dispatch files with the above changes through NEMDE.

17. FEASIBILITY study outcomes – PD formulation APPROACH
The feasibility of the PD formulation approach was assessed based on the ability of the approach to replicate the same price outcomes as the DS formulation on non-intervention days.
25 out of 30 sample days produced similar price outcomes as DS formulation. Example for 14 May 2016 provided below.

18. FEASIBILITY study outcomes – PD formulation APPROACH
3 intervention days (01 Dec 16, 01 Mar 17, April 17) produced similar price outcomes as DS formulation. Example for 01 Dec 2016 below.
Note, no feedback constraints binding during the 3 intervention events.

19. FEASIBILITY study
09 FEB 2017 PRICE OUTCOMES using pd formulation apprOACH
No intervals with NSW & QLD prices > $2000/MWh.
VIC & TAS prices unaffected

20. What-If price using simulated line loadings
09 FEBRUARY 2017 direction event – analysis of potential solutions:
Comparison of price outcomes for DI 1720 HRS
Region
What-If price using simulated line loadings
What-If price using PD formulation
What-If price using DS formulation
NSW
$179.26
$135.84
$13,457.81
QLD
$159.87
$121.55
$11,639.00 SA
$175.28
$199.99
$14,000
TAS
$90.18
$69.46
$40.05
VIC
$148.81
$129.86
$92.05
Both alternate approaches (power flow simulation and PD formulation approach) produced similar and reasonable price outcomes for 09 Feb 2017.

21. FEASIBILITY study
Vic-nsw FLOW using pd formulation apprOACH
Similarly, the flow on other interconnectors were less restrictive with PD formulation approach.

22. 09 FEBRUARY 2017 DIRECTION EVENT – ANALYSIS OF POTENTIAL SOLUTIONS
Do nothing:
Issue can re-occur
Potential for feedback constraints to bind incorrectly affecting dispatch outcomes
Financial impact to market participants in non-intervention regions
Power Flow simulator:
100% reliability required. Simulator should be able to produce simulated line loadings at all times without manual intervention.
For complex power system scenarios, Simulator should be able to produce a valid solution within the 5-min timeframe.
Based on past experience, there is a potential for simulators to break down often requiring manual intervention to resolve.

23. analysis of potential solutions:
Possibility of divergence – pd formulation approach
PD formulation approach when applied to some non-intervention days produced major divergences in price outcomes. An example for 10 Feb 2017 below.
DI = 1520 hrs
Region
Dispatch price_ DS formulation
Dispatch price_ PD formulation
NSW
$427
$426
QLD
$368 SA
$10,585 (reasonable outcome)
$579 (diverging outcome)
TAS
$349
VIC
$418
$419
Reasons for divergence:
Different formulation means a more restrictive constraint using the DS formulation may become less restrictive with PD formulation.
Corollary is that a constraint close to binding using the DS formulation can become binding or more restrictive with PD formulation.

24. OTHER MODELLING ISSUES WITH RERUN APPROACH
Directed generator trapped at the min/max enablement limits of FCAS trapezium in What-If pricing run
What-If pricing run does not see actual output from generators
Once trapped, generators continue to be trapped in What-If pricing run
What-If prices < Intervention prices during some intervals
Occurred during a system strength direction on 02 Sept 2017
Current workaround:
Increase CVP of Intervention and Pricing constraints to override the FCAS min/max enablement limits

25. OTHER MODELLING ISSUES WITH RERUN APPROACH
2. Directed generator tripping during the Intervention.
What-If pricing run does not see actual output from Directed generator
What-If pricing run “oblivious” to the trip of the generator
Directed generator continues to be “dispatched” in What-If pricing run
What-If prices < Intervention prices during some intervals
Occurred during a Direction in SA to maintain reliability on 01 March 2017
Current workaround:
Stop intervention pricing as soon as trip of Directed generator occurs.

26. Matters to consider
Is the rerun approach still appropriate to determine What-If prices considering the modelling issues that seem to persist?
Which options provide the best outcomes overall?
Are there any other approaches the IPWG could recommend?
Does the IPWG think there is a case for change?

27. OTHER items raised AFTER MEETING 1
Consideration of the impact to prices due to potential NSCAS contracts for system strength.
How will intervention pricing be applied when Electranet procures NSCAS via short-term contracts?
Consistency in the use by AEMO of constraints for some generation and Directions/instructions for other participants
System changes or changes to current practices to reduce the need for AEMO interventions.
Efficient and effective use of counter-actions