The Potential Impact of FERC’s SMD Initiative on Renewable Energy Development

1. The Potential Impact of FERC’s SMD Initiative on Renewable Energy Development Kenneth G. HurwitzMarch 25, 2003

2. On the Agenda • SMD summary • Characteristics of wind • 888 reservations vs. SMD rationing via LMP and CRRs • Schedule deviation policies • Interconnection

3. THE SMD RULEMAKING

4. The SMD NOPR • Official name: Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design, Docket No. RM01-12 • Issued July 31, 2002 • Currently on hold pending the issuance of a White Paper by FERC scheduled for late April

5. Major Elements of SMD • Independent Transmission Provider • Network Access Service • Eliminates point-to-point service • Transmission pricing reforms • Embedded costs recovered via access charge paid by load • Usage costs recovered via loss charges and LMP • Open and transparent energy spot markets • LMP and CRRs • Market power mitigation and monitoring • Resource adequacy requirement • Related development: Interconnection NOPR

6. Prospects for the SMD NOPR • Congressional ferment • Headed by opposition from the South and West • State regulators • SMD opposed by PUCs from the South and West • SMD supported by PUCs from states that have restructured • FERC has slowed its plans to implement SMD • FERC now plans to issue a white paper in April to summarize the Commissioners’ revised views on market design

7. The South and SMD • Southern view: let’s return to (or stay with) the good old days before competition • Arkansas recently repealed the State's 1999 electric deregulation law • Virginia: SCC recently recommended delaying a rule that directs utilities to relinquish their transmission assets to an ITP, because SMD “could result in states' involuntary (or possibly inadvertent) loss of day-to-day authority over the price and reliability of electric service for their citizens” • Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, North Carolina: no movement toward restructuring

8. The West and SMD • Western view: SMD will not work in the Western Interconnection, because life is different out west • Reservoir operational constraints • Fish and irrigation constraints • Pockets of market power • Transmission constraints • Hydro short run marginal costs consist largely of opportunity costs, which are hard to forecast accurately • Makes it difficult to formulate bids

9. Bundled Transmission • One of the key issues causing dissension: Does FERC have jurisdiction over transmission bundled with retail sales? • If FERC exercises jurisdiction over bundled transmission, integrated utilities will have to play under the same rules as IPPs • Supreme Court dictum in its opinion on review of Order No. 888 strongly suggests that the Supreme Court would uphold FERC’s assertion of jurisdiction over bundled transmission • Many dissenting states have argued that these suggestions are merely dictum • Note: Dictum from the Supreme Court receives greater deference than dictum from the “Podunk District Court”

10. The Bottom Line • SMD will probably survive • If SMD survives, there probably will be significant regional variations • Even if or where SMD does not apply to vertically integrated utilities, it will still determine the rules for IPPs

11. THE PRIMARY CHARACTERISTICSOF RENEWABLE ENERGY

12. Location, Location, Location • Wind units tend to be far from population (load) centers • In the mountains • On the plains • In the ocean • Location far from load is a disadvantage • More likely on the wrong side of transmission constraints • Rate pancaking • Wind power tends to have a relatively low capacity factor • Because of these two factors, wind power is extraordinarily sensitive to transmission rates, terms and conditions

13. Locational Constraints • Wind units • Must locate where the wind is • Cannot locate in cities • However, these are differences in degree, not in kind, from oil and gas units • Gas units must locate where there is a confluence of water, electric transmission, and natural gas • Gas units cannot locate in cities without a fight

14. Predictability • In the long run, a wind unit’s output can accurately be predicted in a statistical manner • Day ahead, a wind unit’s output forecast is far less predictable than for a thermal unit • The closer to the hour of operation, the more precisely wind output can be forecast

15. 888 Reservationsvs.SMD Rationing

16. The 888 System • Utility: • Calculates Total Transmission Capacity (TTC) • Subtracts network and existing firm point-to-point transmission from TTC to find Available Transmission Capacity (ATC) • Generally, transmission service requests must be granted up the amount of ATC • For point-to-point transmission • Reservations at receipt and delivery points • Generally used only for deliveries through and out of the control area • Network service generally used for native load • “Reservations” are made by the Network Customer’s requesting the Transmission Provider to designate Network Resources and Network Loads

17. Fixed Cost Recovery • Under FERC’s pro forma OATT, fixed costs are recovered by fixed charges set by reference to: • Reserved capacity for point-to-point service • Load ratio share – based on share of peak load – for network service • The point-to-point fixed cost recovery method discriminates against wind units because: • With a low capacity factor – typically about 30% – wind units pay high per unit transmission costs • Wind is unpredictable day-ahead and cannot resell its unneeded transmission capacity

18. Non-Firm is Not Firm • Five reasons that non-firm transmission capacity, purchased an hour or two in advance, is not a good substitute for firm transmission* • Output does not remain constant within an hour • Wind “is not terribly predictable even one hour in advance” • The “process of hourly contracting [is] expensive and uncertain” • For “reasons of financing, intermittent generators often find themselves in need of long-term contracts“ • There is a substantial risk that non-firm service will be curtailed * Source for reasons 1-4: Webber, Stoft and Wiser, Transmission Access Charges and Generation Technology Choice, at p. 3

19. Secondary Markets • Secondary markets for transmission are not the answer to the problem of firm capacity reservations that do not vary with variations in wind patterns (such as season and time of day) • Secondary markets for transmission are thin • The capacity the wind unit would have available for sale would be unpredictable – and therefore unsellable • To use secondary markets the wind unit often would have to sell off-peak, when secondary market demand for transmission is low

20. Accentuate the Positive • Network Access Service • Throws out reservations and the firm/non-firm distinction • “all customers who want physically feasible service will be able to receive service” (SMD NOPR ¶ 144) • Substitutes LMP for reservations of firm transmission • Rationing of transmission capacity according to who values capacity the highest at the time of consumption • Congestion will be the determinant of the allocation of costs • Whoever causes congestion will pay the most • “To the extent the customer is willing to pay congestion costs and transmission losses, its requested transmission service would be available and provided” (SMD NOPR ¶ 145) • Fixed costs paid by access charges assessed to load according to the load’s use of the transmission system THIS IS A VAST IMPROVEMENT FOR INTERMITTENTS DON’T ARGUE WITH THE PACKAGE

21. Eliminate the Negative • Wind needs transmission service only part of the day (or week, month or year) • Elimination of the requirement to pay for a fixed amount of capacity around the clock (and all week, all month or all year) helps wind THIS IS A VAST IMPROVEMENT FOR INTERMITTENTS DON’T ARGUE WITH THE PACKAGE

22. Choose Your Battles Wisely • The anti-LMP argument is weak • The location of generation with respect to transmission constraints carries great economic significance • With the possible exception of the Northwest, it is a losing argument • The PTF vs. non-PTF argument is strong • FERC should eliminate the distinction between PTF and non-PTF, because the existence of non-PTF facilities violates FERC’s policy against pancaked rates • In New England, many renewables are on non-PTF facilities • It is a winning argument

23. Locational Marginal Pricing

24. LMP’s Reasons for Being • LMP is used • To settle imbalances • For bilateral schedules as well as the spot market • To determine congestion charges • LMP provides incentives for • Adjustments in day ahead and real time markets to clear the market at all locations • Construction of generation and/or transmission to relieve constraints • LMP charges congestion costs to those who cause the costs of congestion, instead of socializing those costs

25. LMP Mechanics • Market participants submit price offers a day ahead and/or an hour ahead • With no transmission constraints, LMP is the same at every node, and reflects the marginal cost of energy (the cost of the last – i.e., marginal – generator dispatched to meet load) • LMP at a node reflects the cost of redispatching the system to serve an increment of load at that node • The difference in prices between any 2 locations A and B represents the incremental cost of re-dispatching the system to accommodate the flows between the 2 locations • The congestion charge to transmit energy between A and B is the difference in the LMPs at A and B • Prices typically are calculated every five minutes and then integrated into an hourly price, which is used for settlement

26. Congestion Basics • Congestion charge = MWh x (Day-ahead sink LMP – Day-ahead source LMP) • A bilateral transaction for 50 MW from A to B pays the same for congestion as a trader that sells 50 MW at A and buys 50 MW at B (for simplicity, ignoring losses) • Example: if the LMP at A is $30/MWh and the LMP at B is $40/MWh, the congestion charge for the bilateral transaction will be $10/MWh • The spot trader sells for $30/MWh at A and buys for $40/MWh at B, and therefore implicitly pays a congestion charge of $10/MWh

27. Congestion: Construction Ahead • Because the congestion charge will increase with the level of congestion and decrease as trades are curtailed, the price signal from this approach is consistent with the short run needs of the system to to relieve transmission constraints • The long-run incentive is to build transmission or generation (in transmission constrained areas) to eliminate or avoid constraints • Note, however: it is difficult to align incentives with actual construction of transmission. E.g.: • If an entity is provided CRRs as a reward for constructing transmission that relieves the constraint, what good are the CRRs? • Free rider problem: if one entity pays for facilities necessary to relieve a constraint, all others affected by the constraint also benefit

28. CRR = FTR • CRR = Congestion Revenue Right • FTR = Fixed Transmission Right • An FTR/CRR is a financial contract that entitles the holder to receive compensation for congestion charges • Each FTR/CRR is defined from a point of receipt (where the power is injected onto the grid) to a point of delivery (where the power is withdrawn from the grid) • For each hour in which congestion charges arise between the point of receipt and point of delivery specified in the FTR/CRR, the holder of the right is awarded a share of the congestion charges collected from market participants

29. CRRs = FTRs (cont.) • SMD NOPR mandates two-way obligation CRRs. One would purchase a CRR from “A” to “B”. To illustrate the “two-way” obligation, two cases should be considered: • Case 1: Shipper XYZ incurs and pays congestion charges from “A” to “B.” Shipper holds an FTR/CRR from “A” to “B”. Shipper is compensated by the payment of a share of congestion charge revenues. • Case 2: Same facts except congestion runs in the opposite direction (i.e., from “B” to “A”). Shipper is paid “negative” congestion charges and will be forced to pay the RTO the FTR/CRR amount.

30. Congestion Basics Day-ahead sink LMP – Day-ahead source LMP Congestion Charges LMP at B LMP at A $0/MWh $30/MWh $30/MWh $10/MWh $30/MWh $40/MWh ($10/MWh) $40/MWh $30/MWh

31. Congestion Charges and FTRs LMP at A LMP at B Congestion Charges and FTRs Congestion Charges = $10/MWh (payment) $30/MWh $40/MWh FTR = ($10/MW) (receipt) Congestion Charges = ($10/MWh) (receipt) $40/MWh $30/MWh FTR = $10/MW (payment)

32. If All Goes According to Plan … • An entity with a CRR in the same direction (from A to B) and quantity as his transmission pays (receives) congestion charges (revenues) equal and opposite to his CRR benefits (credits) • The entity has locked in a certain price for transmission • BUT: an entity with a CRR in a different direction (from A to C instead of to B) or quantity from his transmission might not pay (receive) congestion charges (revenues) equal and opposite to his CRR benefits (credits) • If LMP B  LMP C, then the CRR will not precisely offset the congestion charges • The entity has NOT locked in a certain price for transmission • Can arise if (for example): • Point-to-point service using a secondary point of receipt or delivery • Network service using resources in relative combinations different from plans

33. Problems for Intermittents • Two-way obligation CRRs are problematic for intermittent resources • Under such CRRs the holder of the congestion rights receives and pays congestion revenues based on his CRR irrespective of his output • To the extent that a unit’s output is fixed (or varies little), it can bid for CRRs for that output level, and not be affected (or be only slightly affected) by LMP variations • Wind output, however, varies greatly. Therefore, wind units can only imperfectly hedge against changes in LMP.

34. Possible Solutions • Possible solutions to wind’s congestion problems: • Allow wind energy resources to own one-way option CRRs • Wind would receive CRR revenues but not be obligated to pay CRRs • * Eliminate congestion through upgrades • * Allow wind units to submit bids closer to the hour of delivery than other resources are allowed to bid • But this does not help in the case of fixed, 2-way obligation CRRs * Fair Transmission Access for Wind: A Brief Discussion of Priority Issues (AWEA)

35. Imbalances

36. Imbalances • An imbalance is a difference between the scheduled and the actual output or consumption • Two different types of imbalances • Schedule versus generation– does matter to wind • Schedule versus load – does not matter to wind • Imbalances frequently are subject to penalties • Within a narrow band • Paid for over-deliveries at < 100% of decremental cost • Pay for under-deliveries at > 100% of incremental cost • Within a broader band • Paid for over-deliveries at far < 100% of decremental cost • Pay for under-deliveries at far > 100% of incremental cost

37. All Pain, No Gain • Because wind is unpredictable day-ahead: • When, as is common today, imbalance penalties are based on real time deviations from day-ahead schedules, wind units have to pay exorbitant balancing penalties • It’s no accident that all operating wind energy capacity in the U.S. is under tariffs that provide some exemption from energy imbalance penalties or is encompassed in a penalty-free spot market such as PJM. (Milligan & Porter, 2002) • The incentives that imbalance penalties are supposed to provide do not work in the case of wind units • Penalties will reduce deviations – not in the case of wind • Uninstructed deviations harm system reliability – in the case of small wind resources the harm is small

38. FERC on Imbalances • In Order No. 888, FERC said that • Generators should be required to match schedules • Or else they could game the system • In the SMD NOPR, FERC said that • “intermittent resources such as wind power may also benefit from scheduling rules that recognize their inability to precisely control output” • Under SMD, ITPs would settle imbalances at the real-time price • This would eliminate the punitive – penalty – aspect associated with today’s balancing services • However: FERC sought comment on whether the SMD tariff should include penalty provisions for uninstructed deviations that threaten system reliability

39. CAISO Intermittent Schedules • FERC has approved the CAISO method for scheduling intermittent resources (98 FERC para. 61,327 (2002)) • In the SMD NOPR, FERC • Proposed to include the CAISO's scheduling option for intermittent resources as part of SMD • But also sought “comment on whether there is a better way to schedule intermittent resources” • Purpose of the CAISO methodology: • Nearly eliminates imbalance penalties due to non-dispatchable nature of intermittent resources • Facilitates participation by intermittent resources in competitive markets

40. CAISO Scheduling • CAISO and an industry working group developed a forecasting methodology • Participating Intermittent Resources (“PIRs”) must submit schedules day-ahead that are consistent with the forecasts made using the methodology • Updated forecasts of energy are made available to the ISO 30 minutes prior to the operating hour

41. CAISO Imbalances • PIRs are exempt from imbalance penalties • For imbalance resolution, deviations are summed across the month (monthly netting) at average prices • The difference between what PIRs are charged on a monthly basis and what they would have been charged if deviations were settled at regular interval is tracked in a balancing account and settled among intermittent resources in the aggregate • Because forecasting models will be statistically unbiased, ISO expects deviations to be small or zero

42. CAISO Requirements • Static and dynamic requirements for PIRs • Install ISO-approved meter • Install ISO-approved Data Processing Gateway • Submit schedule consistent with an hourly energy forecast developed under ISO supervision • PIRs are assessed a fee to defray ISO’s forecasting costs • ISO monitors the program for: • Costs to the ISO and Market Participants • Impacts on grid operations and reliability

43. Interconnection ofNew Generating Facilities

44. Interconnection Basics • Interconnection is a form of transmission service (Tennessee Power Company, 90 FERC para. 61,238 (2000)) • It is distinct from the delivery component of transmission service • As a transmission service, it is regulated by FERC • Becoming interconnected with the transmission grid does not provide any assurance of obtaining transmission delivery service

45. The Basic Process • The interconnection process on its face is simple • The generator files an application for authorization to interconnect its facility • The utility studies the facilities needed to interconnect the generator to the grid • The utility and the generator enter into an Interconnection and Operating Agreement • In practice, the process is full of pitfalls

46. The Study Process • Three increasingly costly, complex and exact studies are performed • Feasibility Study • System Impact Study • Facilities Study • Queues • One at a time • Buckets • The studies frequently take longer than they are supposed to take • Interconnection studies rarely are transparent • Black-box models with many unclear assumptions

47. Who Performs the Studies? • Under an RTO setting, it is the RTO – not the TO – that performs the study • However, TO personnel may still perform the study, albeit under the supervision of RTO personnel • Otherwise, the TO performs the studies – which leads to self-dealing/bias • Gold plated facilities • Gold plated construction • PJM’s tariff provides that the generator may select the contractor

48. Next, the I&OA • It may prove difficult to negotiate the I&OA • The TO has fought this fight before • The TO will fight this fight again • For small generator, litigation is expensive relative to the cost of the project • Litigation is time consuming • Delay hurts the generator – not the TO • The TO is not penalized for taking unreasonable positions • The issues that arise in specific interconnections are complex, not easily understood by third parties (i.e., FERC)

49. Facilities Costs • Facilities costs fall into two categories • Direct Assignment Facilities • Paid for by the generator • Network Facilities • Also paid for by the generator, but, generally speaking, generator is entitled to a credit against future transmission costs, plus interest • Existing exception for certain RTOs, such as PJM

50. Network Facilities • Generally, facilities “at or beyond” the point of interconnection with the transmission grid • Transmission Grid Facilities are those that operate “for the general benefit of all users” of the transmission system • FERC has rejected the “but for” test • FERC has adopted a “less cramped” view of what constitutes a system benefit. For example, facilities that merely prevent degradation of the reliability of the transmission system have been held to benefit all users. • However, the upgrade cannot be a “sole use” facility