Financial Transmission Rights: Design options

1. Financial Transmission Rights: Design options Presentation to Electricity Commission 2 September 2009

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

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

13. Energy contract – example 2 Generator 1 Offered at $2 240 MW dispatched • 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) $2 200 MW Load 1 300 MW Constrained 40 MW Load 2 60 MW • To meet obligation of 300MW at B retailer must purchase all 300MW at B for $4 ($1200) $4 160 MW $3 • Additional cost to gentailer is equivalent to the rentals of the system ($600) Generator 2 Offered at $3 120 MW dispatched Third party load increases at B

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 $2 200 MW Load 1 300 MW Constrained 40 MW Load 2 60 MW $4 160 MW $3 Generator 2 Offered at $3 120 MW dispatched

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. Energy price hedge values differ by location and over time

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. 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. Rental flows without FTRs Those who pay for transmission Allocation minimises impact on nodal prices – not paid to energy purchasers Rentals allocation mechanism (TPM) Rentals Electricity market

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

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. 2002 FTR design 2009 FTR recommendation 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 No pre-allocation Pre-allocation to investors Pre-allocation of FTRs

23. 2002 FTR design Coverage • Node to node, hubs and nodes, hubs only • Market power? • Start simple HVDC only 2 hubs Large hubs Small hubs Interconnected grid Whole grid Low coverage, Simplicity High coverage, Complexity FTR coverage 2009 FTR recommendation

24. 2002 FTR design Constraints only? • Losses should be reasonably predictable • Constraints are not predictable • FTRs with losses are complicated and confusing Constraints only Losses and constraints Losses and constraints 2009 FTR recommendation

25. 2002 FTR design Revenue adequacy • Dependent on FTR grid design • Incorrect grid outage assumptions, unplanned outages, emergencies 2009 FTR recommendation To FTR market operator/grid owner To FTR market participants FTR Revenue Risk

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. Revenue adequacy in PJM

28. FTR Duration • Any duration required • Start low for accelerated learning • Change with market requirement Hours Weeks Months Years Decades 1 Month FTR duration Long duration Short duration 2002 FTR design 2009 FTR recommendation

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 Obligations or options Obligations Options 2002 FTR design 2009 FTR recommendation

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

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