An LP Formulation for Inter-Island Trading of Regulation Services

1. An LP Formulation for Inter-Island Trading of Regulation Services EPOC, September 2008 E Grant ReadUniversity of Canterbury and EGR Consulting Ltd

2. Disclaimer • This presentation relates to a draft formulation that may be subject to revision • The views expressed are solely those of the author, and not necessarily shared by Concept Consulting, the Electricity Commission, or the System Operator • No opinion is expressed or implied as to whether this, or any other formulation, should be implemented in New Zealand.

3. Outline • Ancillary service co- optimisation • Why is regulation different? • Issues to be accounted for • Simplifying assumptions • The mathematics of implementing regulation • Potential gains from inter-island trading • LP formulation for regulation trading

4. Ancillary service co-optimisation • The New Zealand electricity market pioneered co-optimisation of energy and ancillary services • Two contingency (raise) response services traded, separately, for each AC island system • This was generalised in Australia • Six contingency (raise/lower) response services in a multi-regional AC system • Plus “frequency keeping” (or “regulation”) • Plus (recently) limited modelling of constraints on HVDC link to Tasmania

5. Why is regulation different? • Regulation (or “Frequency Keeping”) is: • About continuous response to essentially symmetric fluctuations in the generation/load balance (maintaining constant frequency) • Not about occasional response to large asymmetric contingencies (ie unit/link failure) • Regulation is not coordinated by providers responding independently to a rapid frequency drop in an AC system • If shared between several providers, it is coordinated by: • Calculating and apportioning the required adjustment, and • Communicating this via “Automatic Generation Control” (AGC) • This calculated response can : • Take account of requirements in each AC island sub-system • Allow inter-island trading or sharing

6. Issues to be accounted for • Participant offers • Assumed to have the same form as for current ancillary services (other markets use a different form) • Unit freeboard capacity • Providers must be able to swing production both up and down • AGC range limits • Units can only be controlled within limits of AGC equipment • Ramp rate limits • Providers must be able to swing production at an acceptable rate • Joint ramping restrictions • That rate may be limited by ramping for other purposes • HVDC freeboard capacity • Nett impact of two island swings can not breach constraints

7. Simplifying assumptions • We will ignore: • AGC implementation issues • No group dispatch • Intra-interval re-dispatch • Ramping limits • AGC range limits • Losses • We will assume: • Simple HVDC limits • A symmetric up/down regulation service • Constant participation factors in each dispatch interval

8. Implementing Regulation • PID feedback control algorithm calculates aggregate island response requirement: • Proportional to current frequency deviation, and/or • Integral of recent frequency deviations, and/or • Differential of frequency deviation • Unit participation factors (PF) must allow for: • Proportional sharing of regulation duties within each island • Inter-island sharing of duties so as not to violate HVDC limits • These do not appear directly in the LP formulation, but yield useful insights

9. Participation Factors • Requirement for symmetric linear/proportional response is actually quite restrictive • Response for each unit is a proportional share of aggregate island response, RESPi, given by: • So nett increase in South-North transfer must be: • And remember, this must be symmetric, irrespective of the direction of HVDC transfer for energy purposes.

10. SI Response Requirement Response Requirements? Swing Implications of Island Requirements NI Response Requirement HVDC swings North HVDC swings South MIN >> National total swing >>MAX

11. BIG QUESTION? • Is inter-island trading of regulation supposed to deliver gains from: • Regulation sharing, or • Regulation transfer? • They are both valuable, but • They are not the same, and • We can not use the same HVDC capacity for both

12. Base Case: No trading • Aggregate response in each island equals aggregate requirement in that island: • In other words: Each island meets its own requirement There is no change to South-North transfer And the market must clear: .

13. Limiting Case: Sharing only • With no nett transfer of regulation service, the market must still clear : • But we can use HVDC swing capacity to share actual response • This keeps HVDC swing to: • ZERO when both island requirements move up/down together • HReg when island requirements move in opposite directions

14. Limiting Case: Transfer only • If nett transfer of regulation is allowed, ignoring benefits from sharing, the market can clear : • If we use all the HVDC swing capacity, HReg, for (say) South to North regulation transfer, we get: • In other words, there is no reciprocal sharing, but: • SI meets all its own requirement, plus as much as possible of the NI requirement, given HVDC swing capacity • NI ignores SI requirement, just meeting residual NI requirement

15. Trade-off • The above formulae can be generalised to allow simultaneous sharing and transfer, but: • HReg must be allocated between transfer and sharing • HReg ≤ Hcap… the HVDC freeboard • Gains may be made by using AGC to develop a competitive market within each island, but further: • Transfer reduces market purchase costs by allowing purchase from the cheaper island, while • Sharing brings operational benefits by reducing probability of extreme island responses ...although this only reduces market purchase costs if island requirements are reduced to reflect this

16. NOTE • None of this depends on the underlying direction of HVDC energy transfer • So, at any time we may have (for example): • Energy being traded from North to South, with • Regulation being traded from South to North • In real time, this means that: • Regulation service will be delivered from South to North, • By varying the fundamental North-South energy flow (In principle this could involve reversing HVDC flow direction, but we do not allow this because there is a “no-go” zone around zero HVDC flow)

17. (Limit imposed by possible upswing for regulation purposes) (HReg) (Absolute limit on acceptable up/downswing for regulation purposes) (Limit imposed by possible downswing for regulation purposes) HVDC freeboard (HCAP) HVDC energy flow LP may set Hreg <Hcap to avoid counter-productive excess “sharing” HVDC limits: HReg feasible region

18. LP formulation for regulation trading(if sharing does not reduce requirements) SI regulation purchase (SReg) National requirement SN transfer limit (no sharing) SReq+HCap Balance point (no transfer, only sharing) SReq SReq-HCap NS transfer limit (no sharing) NReq-HCap NReq NReq+HCap NI regulation purchase (NReg)

19. .. and if sharing does reduce requirements Balance point moves in to reflect gains from sharing spare swing capacity not used by trading SReg Balance line SN limit SReq+ HCap SReq NS limit SReq- HCap NReq-HCap NReq NReq+ HCap NReg

20. Conclusion • This formulation should allow symmetrical inter-island trading of regulation service • Constraints also developed to deal with ramping issues etc • Some issues to be resolved wrt interaction with SPD ramp limits, 5 minute (re-) dispatch, HVDC state modelling, etc • An issue arises as to whether “sharing” should reduce national requirements • The optimal solution does not necessarily use all available HVDC swing capacity • Implementation is only possible if some form of AGC is actually implemented • The costs and benefits have not been quantified (by me)