Electricity transmission pricing: getting the prices “good enough”?

1. Electricity transmission pricing: getting the prices “good enough”? Richard Green Institute for Energy Research and Policy

2. Transmission pricing • Geographical differentiation in the wholesale market • Prices for connecting to and using the transmission network

3. Six objectives • Promote the efficient day‑to‑day operation of the bulk power market • Signal locational advantages for investment in generation and demand • Signal the need for investment in the transmission system

4. Six objectives • Compensate the owners of existing transmission assets • Be simple and transparent • Be politically implementable Green (Utilities Policy, 1997)

5. Three approaches • Ignore transmission issues • Ignore transmission issues, then bribe market participants to sort things out • Integrate transmission issues into your market design(s)

6. Major power flows Source: UCTE

7. Major power flows and congestion Congested 26-75% 76-99% 100% Source: UCTE

8. PH Pricetrade PL Mpts If costs differ between areas P P GW GW Xpts

9. Pricetrade If costs differ between areas P P GW GW Mpts Xpts

10. Pricetrade If costs differ between areas and the lines are too thin… P P GW GW Mpts Xpts

11. If costs differ between areas and the lines are too thin… P P T { GW GW Mpts Xpts

12. Pricetrade If costs differ between areas and the lines are too thin… you could still ignore the problem P P GW GW Mpts Xpts but someone will want money to sort it out!

13. Zones in the NEM • NEM runs nodal model and dispatches according to nodal conditions (prices) • Generators / loads grouped into regions • All generators in a region receive the regional reference price • Marginal cost at a reference node • No compensation for constrained running

14. From a line to a network… • Electricity will flow along every path between two nodes • It “cannot” be steered • If one line fails, the flows instantly change • Overloading any line can be catastrophic

15. (for example…)

16. The impact of loop flows A B C

17. The impact of loop flows A B C

18. Nodal prices • Set price of power equal to marginal cost at each point (node) on the network • Marginal cost of generation (if variable) • MC of bringing in power from elsewhere • Centralised market uses the nodal prices • Bilateral trades which move power pay the difference in nodal prices

19. Nodal trading • Price at A = 20, Price at B = 30 • I sell at A, I receive 20 • I sell at B, I receive 30 • I generate at A and sell at B, I receive the agreed bilateral price and pay (30 – 20) • I generate at B and sell at A, I receive the agreed bilateral price and pay (20 – 30) B A

20. The impact of loop flows and constraints A B 6 MW at C needs 3 MW from A and 3 MW from B C

21. Prices – constraint AB • Price at C = (Pa + Pb)/2 • 1 MW extra capacity allows 1.5 MW from A to replace 1.5 MW from B • Shadow cost of constraint = 1.5 (Pb – Pa) • If Pa = 10, Pb = 30 • Pc = 20, shadow cost = 30 • Pc = Pa + 1/3 shadow cost = Pb – 1/3 shadow cost

22. A B C The impact of loop flows and constraints 3 MW at C needs –3 MW from A and 6 MW from B

23. Prices – constraint AC • Price at C = 2Pb – Pa • 1 MW extra capacity allows 3 MW from A to replace 3 MW from B • Shadow cost of constraint = 3 (Pb – Pa) • If Pa = 10, Pb = 30 • Pc = 50, shadow cost = 60 • Pc = Pa + 2/3 Shadow cost = Pb + 1/3 Shadow cost

24. A B C The impact of loop flows and constraints 3 MW at C needs 6 MW from A and –3 MW from B

25. Prices – constraint CB • Price at C = 2 Pa – Pb • 1 MW extra capacity allows 3 MW from A to replace 3 MW from B • Shadow cost of constraint = 3 (Pb – Pa) • If Pa = 10, Pb = 30 • Pc = –10, shadow cost = 60 • Pc = Pa – 1/3 shadow cost = Pb – 2/3 shadow cost

26. Summary

27. Implications • Nodal prices can vary significantly • Over time • Over space • The first creates a need for hedging • The second makes it harder • The prices may be counter-intuitive

28. How to hedge • Transmission Congestion Contract • Spatial contract for differences • Pays the holder the difference in nodal prices between two specified points (from A to B) • Price at B – Price at A • Perfect hedge if you generate that amount of power at A and sell it at B • Remember the real-time charge is (PB – PA)

29. Who’d sell that hedge? • The spot market charges raise a surplus • Who gets it? • If the Transmission Congestion Contracts allocation is feasible, Hogan (1992) shows spot market surplus ≥ TCC payments • Organisation receiving the spot surplus can issue TCCs and find itself hedged!

30. Inferior ways of hedging • Financial Transmission Rights (options) • Only pay out when value is positive • Payments may exceed spot revenues • Physical Transmission Rights • Limited by system capacity • If line limit on AB is 100, can only issue 100 • With TCCs, 100 BA “allows” an extra 100 AB • “Smeared” share of congestion revenues

31. What if you get it wrong? • Operational difficulties • PJM’s first market • Economic operating mistakes • Investment mistakes • At present, we don’t know much about these

32. How much does it cost to get it wrong? • Compare demand and operating patterns with different pricing rules • Model applied to England and Wales, 1996 data • Numbers are country- and time-specific • Approach is general

33. The model • NGC system in 1996/97 • Thirteen zones (two pairs of NGC’s zones are combined, one zone split into two) • Iso-elastic demand in every zone • Generation in most £/MWh Gas, Coal, Nuclear Oil GW

34. Transmission system model North A DC load flow model with losses (proportional to the square of flows) and constraints on the total flows across NGC’s system boundaries South-West

35. Three pricing rules • One price for generation and for demand in each zone (optimal) • One price at each node for generation, but a common national price for demand • One national price for generation and one national price for demand (actual system) • Constraints are managed via payments for constrained-on and constrained-off running

36. What is welfare? • NGC’s operating surplus • Kept the same under each of the rules • Generators’ operating surpluses • Energy revenues less variable fuel costs • Gas contracts assumed not to be variable • Consumer surplus • Area under their demand curve and above the price they actually pay

37. Prices – winter peak

38. Prices – summer trough

39. Basic results

40. Intuition for the results • Adjustments to generation for constraints have to happen, whatever the pricing rule • Here, these are in the same direction as the economic response to marginal losses • Cost differences at stations partially offset marginal transmission losses

41. Market power • Sometimes a problem in this market • General incentive to raise prices • Particular incentive to raise prices in import-constrained area • Uniform pricing gives incentive to reduce prices in export-constrained area • Model two strategic generators plus fringe • Both firms change slope of bids (by region)

42. Generators’ capacities North South-West

43. Prices – winter peak

44. Prices – summer trough

45. Prices – zone 12

46. Prices – zone 1

47. Market power

48. Conclusions of this study • Optimal pricing would create winners (northern consumers, southern generators) and losers (northern generators, southern consumers) • It would be less vulnerable to market power • Welfare gains of 1% of turnover are quite large as Harberger triangles go!

49. Other transmission charges • Connection assets – local costs • Capacity-based use of system • Affect investment decision, not operating choices • Output-based use of system • Affect operating choices and might be used to offset consistent errors in the market rules • Contracts for constrained running

50. Interactions between charges • Investing generators should consider both spot market and transmission charges • With the right spot signals, transmission charges should be uniform • Differentiated transmission charges needed if spot prices send inadequate signals • Using both would over-signal, reducing transmission costs, but raising generators’