1. For discussion purposes only Financial Transmission Rights: Design options Presentation to Electricity Commission 2 September 2009

2. © Transpower 2009 For discussion purposes onlyslide 2 Background Transpower was asked for advice on how to: –Simplify and make 2002 FTR more appealing to participants –Deal with Dr Read’s 2002 concerns –Implement an FTR market

3. © Transpower 2009 For discussion purposes onlyslide 3 Background Transpower’s advice is a suggested starting point for discussion Pricing should reflect underlying physics FTRs are internally consistent with locational marginal pricing Regulatory arrangements are different to 2002 FTR trading platform can be significantly simplified without affecting dispatch Start simple and evolve with users

4. © Transpower 2009 For discussion purposes onlyslide 4 What is the problem? Nodal prices are consistent with physical dispatch (i.e. they obey the laws of physics!) Locational price differences are caused by constraints in the transmission system NOT energy availability Commercial implications of transmission constraints: –Bilateral contracts can only hedge energy costs –Volatile and unpredictable locational price differences must be hedged separately

5. © Transpower 2009 For discussion purposes onlyslide 5 What is the problem? There is little ability to hedge locational price difference Incentive is to vertically integrate and regionalise generation and retail Consequences: –At best a partial locational price hedge –Barrier to retail competition –Significant cost to consumers –Inefficient use of transmission assets

6. © Transpower 2009 For discussion purposes onlyslide 6 What are the possible solutions? Remove locational price differences altogether –Removes demand side response Use “rentals” to fund a hedge product –The net amount that needs to be hedged is EXACTLY the rentals collected –Preserves demand side “signals”

7. © Transpower 2009 For discussion purposes onlyslide 7 Report Structure Part 1 – what is an FTR? How do they fit into integrated market design? Part 2 – design options Part 3 – implementation options

8. © Transpower 2009 For discussion purposes onlyslide 8 Markets with locational marginal pricing A system for the efficient trading of electricity using supply and demand to set price Separate contestable and monopoly functions Characterised by “spot prices” that differ by location Wholesale market = competitive trading Retail market = customer choice

9. © Transpower 2009 For discussion purposes onlyslide 9 Integrated market design Co-ordinated spot market Bid-based, security- constrained, economic dispatch with nodal prices ENERGY PRICING Bilateral contracts at nodal price differences TRANSMISSION PRICING Non-distortionary access charges NEW INVESTMENT Market-driven RISK MANAGEMENT Hedge against locational price differences NEW GENERATION Location and timing NEW TRANSMISSION Location and timing DEMAND SIDE PARTICIPATION NEW TRANSMISSION Centrally planned, regulatory process, TPM TRANSMISSION CONGESTION FTR, LRA, vertical integration RISK MANAGEMENT Hedge against locational price differences TRANSMISSION CONGESTION FTR, LRA, vertical integration

10. © Transpower 2009 For discussion purposes onlyslide 10 Physics – Kirchoff’s law This means that... –Every injection into and off-take from the grid effects electricity flows on every circuit –Physical capacity rights cannot be meaningfully defined Which leads us to constraints and nodal prices...

11. © Transpower 2009 For discussion purposes onlyslide 11 Commercial risk Kirchhoff's law and the occurrence of constraints create commercial risk: –Actions of other parties can impact on nodal price –Constraints impact on nodal prices Two primary risk management tools –Bilateral energy contracts referenced against price at a node (often internalised by vertical integration) –Hedge to manage locational price risk arising from constraints

12. © Transpower 2009 For discussion purposes onlyslide 12 Energy contract – example 1 Generator Offered at $2 300 MW dispatched Load 300 MW 200 MW 100 MW At limit $2 Vertically integrated utility generates at A, commitment of 300 MW at $2 at B Generation: Cost to generate at A:-$600 Gets paid at A $600 Retail: Buys 300MW from A -$600 Gets paid for 300MW at B: $600

13. © Transpower 2009 For discussion purposes onlyslide 13 Energy contract – example 2 Third party load increases at B Generator 1 Offered at $2 240 MW dispatched Load 1 300 MW 200 MW 160 MW 40 MW Constrained Generator 2 Offered at $3 120 MW dispatched $2 $4 $3 Load 2 60 MW Line A – B constrained Price at B increases to $4 Retailer can’t meet obligation of 300MW at its generation cost of $2 to load at B ($600) To meet obligation of 300MW at B retailer must purchase all 300MW at B for $4 ($1200) Additional cost to gentailer is equivalent to the rentals of the system ($600)

14. © Transpower 2009 For discussion purposes onlyslide 14 From an energy contract perspective The transmission price risk between A and B is the price difference B − A –Generation at A cannot offer an energy contract referenced at B without taking the transmission price risk –Load at B cannot accept an energy contract referenced at A without taking the transmission price risk Generator 1 Offered at $2 240 MW dispatched Load 1 300 MW 200 MW 160 MW 40 MW Constrained Generator 2 Offered at $3 120 MW dispatched $2 $4 $3 Load 2 60 MW

15. © Transpower 2009 For discussion purposes onlyslide 15 How can A or B manage the transmission price risk? Either A or B needs a financial product that recompenses the value (PriceB - PriceA)/MW. –Generation at A can then offer a fixed energy price at B, or –Load at B can accept a fixed energy price hedge referenced at A The only cash stream correlated with nodal price differences is the rentals FTRs use this correlation to hedge price differences

16. © Transpower 2009 For discussion purposes onlyslide 16 Energy price hedge values differ by location and over time

17. © Transpower 2009 For discussion purposes onlyslide 17 Features of FTRs – trading risk Can be matched to an energy contract of a specified capacity and duration between two nodes – near perfect hedge Holder receives the rentals between two specified points for an agreed capacity and duration Protect the holder against extreme price risks (constraints, scarcity pricing) Can be allocated explicitly and/or through an auction Traded in secondary auctions or markets Only known product that exploits correlation of rentals with locational price differences

18. © Transpower 2009 For discussion purposes onlyslide 18 Features of FTRs – efficient investment Grid could operate with more constraints (more efficient) Signal the market value of constraints (FTR auction value) Provide an important economic signal to assist with the correct location and timing of new transmission investment

19. © Transpower 2009 For discussion purposes onlyslide 19 Rental flows without FTRs Electricity market Rentals allocation mechanism (TPM) Rentals Those who pay for transmission Allocation minimises impact on nodal prices – not paid to energy purchasers

20. © Transpower 2009 For discussion purposes onlyslide 20 FTR market participants Rentals Residual revenue Post allocation mechanism Electricity market participants FTR Auction mechanism FTR pre- allocation mechanism (optional) Auction revenue Net revenue Auctioned FTRs Preallocated FTRs FTR payments Cash flows with FTRs FTR rentals + premium FTR rentals Rentals + premium

21. © Transpower 2009 For discussion purposes onlyslide 21 Design emphasis? Merchant new investment? –Network investment governed by Part F of EGRs –Merchant investment in connection assets possible (probable?) –Allocation of FTRs to investors not high priority in short term Locational hedging –Reduce reliance on physical hedging –Reduce barriers to new retail entry (increased competition) –Provide means to fully hedge against transmission congestion High degree of user influence on design Start simple and build with experience and need WHAT DOES THIS MEAN FOR DESIGN?

22. © Transpower 2009 For discussion purposes onlyslide 22 New Investment New investment –Merchant investment no longer the primary mechanism for transmission upgrades –Allocation of FTRs to investors not high priority in short term Pre-allocation of FTRs Pre-allocation to investors No pre- allocation 2009 FTR recommendation 2002 FTR design

23. © Transpower 2009 For discussion purposes onlyslide 23 Coverage Node to node, hubs and nodes, hubs only Market power? Start simple FTR coverage 2002 FTR design High coverage, Complexity Low coverage, Simplicity 2009 FTR recommendation HVDC only 2 hubs Large hubs Small hubsInterconnected grid Whole grid

24. © Transpower 2009 For discussion purposes onlyslide 24 Constraints only? Losses should be reasonably predictable Constraints are not predictable FTRs with losses are complicated and confusing Losses and constraints 2002 FTR design Constraints only 2009 FTR recommendation

25. © Transpower 2009 For discussion purposes onlyslide 25 Revenue adequacy Dependent on FTR grid design Incorrect grid outage assumptions, unplanned outages, emergencies FTR Revenue Risk 2002 FTR design To FTR market participants To FTR market operator/grid owner 2009 FTR recommendation

26. © Transpower 2009 For discussion purposes onlyslide 26 Revenue adequacy PJM, CAISO, MISO –FTR Credits are prorated proportionally Payments derated when revenue shortfall occurs Excess rentals and auction revenue occurring over a month are transferred to a balancing fund At end of period balancing fund is used to clear unpaid FTRs (pro rata) –NYISO Revenue shortfall is compensated for by imposing an uplift charge on transmission owners Attempts to link transmission maintenance standards with revenue adequacy

27. © Transpower 2009 For discussion purposes onlyslide 27 Revenue adequacy in PJM

28. © Transpower 2009 For discussion purposes onlyslide 28 FTR Duration Any duration required Start low for accelerated learning Change with market requirement FTR duration 2002 FTR design Long duration Short duration 2009 FTR recommendation Hours WeeksMonthsYearsDecades 1 Month

29. © Transpower 2009 For discussion purposes onlyslide 29 Obligations or options? Obligation FTRs can become a cost (obligation FTRs are directional) Obligation FTRs still hedge price difference even when –ve Option FTRs always cash positive BUT lower capacity and computationally different Options Obligations or options Obligations 2002 FTR design 2009 FTR recommendation

30. © Transpower 2009 For discussion purposes onlyslide 30 Post allocation of residual revenue Any allocation possible Change results in value transfers Simplest approach is to initially make no change Pre-allocation of FTRs Pre-allocation to investors No pre- allocation 2009 FTR recommendation 2002 FTR design

31. © Transpower 2009 For discussion purposes onlyslide 31 Implementation Transpower’s system is “up and running” Can assist establishing an FTR market quickly if required Transitional arrangements could see separation of systems from Transpower