RTO 101: What RTOs Do and Why S ession 1 - System Operations Session 2 - RTO Spot Markets

1. RTO 101: What RTOs Do and WhySession 1 - System OperationsSession 2 - RTO Spot Markets Prepared by John D. Chandley for PJM and Midwest ISO States May 2008

2. Topics for This Meeting • Session 1: Understanding System Operations • System operations, dispatch and reliability • Many control areas but one grid • How RTO dispatch replaces local dispatches to improve reliability • How the RTO dispatch automatically creates a spot market • Session 2: Advanced RTO Spot Markets • Inter-RTO coordination and Joint/Common Markets • Day-ahead and real-time markets – two-settlement systems • How RTOs support DR, contracting, renewables, climate issues • EXTRA: How RTOs meet FERC’s open access requirements 2

3. Topics for This Meeting (cont.) • Session 3: Locational Marginal Pricing • Why LMP and not something else? • LMP example and observations • Session 4: Financial Transmission Rights • How FTRs work • How FTRs are allocated • Are there enough FTRs? • Session 5: Resource Adequacy in an RTO Framework • The “missing money” problem • Path B: Capacity payment approaches to the problem • Issues with earlier capacity approaches • Reform approaches in NY, NE, and PJM’s RPM • Path A: Can MISO avoid a capacity market? Convergence? 3

4. Understanding System Operations 4

5. A Utility Is Commonly Thought of as Having Three Major Operational Functions: Generation . . . Transmission . . . Distribution . . . But there is another function – SYSTEM OPERATIONS 5

6. ISOs and Most Utilities Have a Control Room for System Operations(This is MISO’s; PJM & large utilities have them) 6

7. System Operators Work in Local Dispatch Centers That Manage “Control Areas” • A control area may cover one utility grid/service area, or two or more interconnected grids. An RTO may cover a broad region. • There are over 140 control areas in the United States alone. • Each control area manages only a piece of an interconnection. • In fact, there are only three very large “interconnections.” • Dozens of separately owned grids/control areas are interconnected. • And energy flows travel throughout each interconnection along all possible paths – the laws of physics dictate this. • Each interconnection functions like one huge electrical machine. 7

8. 8

9. Essential Reliability Functions Center Around Each System Operator’s Dispatch Maintain Voltage and Frequency Coordinate Inter-utility Flows w/Others Security- Constrained Economic Dispatch & Regulation Real-Time Balancing TLR Congestion Redispatch (internal only?) Grid Operating Instructions Monitor Flows, Limits & Contingencies Manage Operating Reserves Keep Flows Within Limits 9

10. + Losses A System Operator’s Dispatch Matches Supply and Demand Every Second • Dispatchers instruct generators how much to generate at each location in each dispatch interval (usually every 5 minutes). • There’s virtually no “storage” in electricity, so electricity must be generated as it is consumed. • Automated “regulation” fine tunes output in seconds to balance supply/demand at all times. • Energy dispatch keeps frequency at 60Hz • Reactive power dispatch keeps voltage stable • These and other actions keep the lights on = = Demand Total MW Supply Total MW 10

11. UNCONSTRAINED MERIT ORDER DISPATCH 80 System Load 60 East Gas Running Costs/ Bids ($/MWh) 40 Must run? West Gas South Gen 20 East Coal West Nuke 0 0 100 200 300 400 500 Capacity (MW) The System Operator’s Dispatch Also Tries to Meet Demand At Lowest Cost $/MWh • Operators try to dispatch economically. $50 $40 $35 $30 $20 11

12. Security-Constrained Economic Dispatch: Congestion Requires Operators to Dispatch Out of Merit Order to Avoid Overloading Transmission. “Redispatch” is Needed, but It Raises Costs $60 Demand $50 Constrained-On Unit Unconstrained Merit Order Marginal Cost Or Clearing Price Least cost Redispatch Units H & N are the most cost-effective to constrain off and on to relieve the constraint $40 $30 Q P O N Constrained-Off Unit M $20 L K J I H $10 G F E D C A B 12 $0

13. RTOs Are Regional Open Power Pools • Power pools solve important reliability and network coordination problems that cannot be ignored. Pools were inevitable. • PJM, ISO-New England and NY ISO started as power pools • California ISO is a power pool for the three large private utilities • ERCOT is a power pool for most of Texas’ utilities • MISO is a new power pool for many utilities in the Midwest. • Large non-RTO utilities created closed pools (Southern, Entergy) • How these pools operate explains the basic structure of wholesale electricity markets. 13

14. RTO Functions Maintain Voltage and Frequency Coordinate Flows Real-Time Balancing Regional Security- Constrained Economic Dispatch Manage Congestion Control Grid Operations Monitor Grid Manage Reserves Keep Flows W/in Limits An RTO Uses a Regional Dispatch To Replace Local Control Area Dispatches Coordinate with other RTOs Original Control Area A Original Control Area B TLR Original Control Area D Original Control Area C TLR 14

15. RTO Open Power Pools Create Spot Markets • Once you create a dispatch power pool, and open it to everyone, it automatically creates a spot market. • Quantity/price offers/bids determine who gets dispatched. • ISO-Pool has to pay generators/sellers for the energy they inject. • ISO-Pool has to charge loads/buyers for energy they withdraw. • ISO-pool has to charge/pay everyone for their imbalances. • ISO must charge/pay for redispatch to relieve congestion. • A spot market and spot prices flow directly from the dispatch. 15

16. Market Support Market Inputs Reliably Serve All Loads Ensure Reliability Generator Offers $/MWh at A Reserves Cover Imbalances Co-Optimized Real-Time Balancing Regional Security- Constrained Economic Dispatch Load Bids $/MWh at B Buy and Sell Spot Energy Bilateral Schedules e.g., A to B Congestion Redispatch (In lieu of TLR) Transmission Usage Charge Pay (LMPB - LMPA) Calculate Dispatch Prices (LMP) Self Schedules In at A, out at B, C to D, etc Allocate Firm TX Rights Financially Firm Rights Receive (LMPB - LMPA) Use LMPs for Settlements $$$ $$$ RTOs with Standard Core Features Enhance Grid Reliability – And Create Spot Markets RTO Functions 16

17. Reliability and Spot Markets Are Linked • An open spot market arises naturally from . . . • The reliability necessity of a security-constrained dispatch • The desirability of having an economic (“least-cost”) dispatch • The commercial necessity of paying/charging all parties that use the dispatch at market prices • Reliability is supported by spot market prices linked to dispatch. • Prices consistent with the dispatch and offers/bids encourage parties to follow dispatch instructions and use the grid efficiently. • If prices are inconsistent with dispatch, reliability can suffer. • (e.g., early PJM, California, etc) 17

18. The Energy Spot Markets Are “Voluntary” • No one is forced to buy energy from the RTO spot markets or sell energy into the spot market • Any LSE/utility can self-schedule its own generation to its own loads – load is served at the LSE/utility’s generation costs • Any entity can arrange pt-to-pt contracts to serve its loads – load is served at the price of the bilateral contract • But parties that use the dispatch/spot market must accept its settlements • Parties that have imbalances/deviations settle at spot prices • Parties that buy/sell “extra” energy through the dispatch also settle at spot prices. 18

19. Session 2. Common Features of RTO Spot Markets • Day-ahead and real-time markets • Inter-RTO Coordination and Joint Market • How RTOs support policy options 19

20. RTO May Operate Multiple Spot Markets • There is always a “real-time” spot (balancing) market • The Real-time market flows from the real-time dispatch • But US RTOs use the same approach to create a day-ahead spot market • Day ahead, the RTO accepts schedules, offers and bids. It arranges a day-ahead security-constrained economic dispatch • The RTO then prices the dispatch to define day-ahead LMP prices for spot energy and day-ahead usage charges 20

21. DA Inputs Day-Ahead Market for Day-Ahead Trades Sets Up Real-time Reliability and Dispatch RTO DA Functions DA Outcomes Generator Offers Enough Capacity Committed to Meet RT Loads Commitment Co-Optimized Reserves Load Bids and Forecasts Co-Optimized Day-Ahead Schedules DA Regional Security- Constrained Economic Dispatch Self Schedules (and virtuals) Imports and Exports Cash Out FTRs MW * (LMPB - LMPA) Calculate DA LMPs Pay Usage for DA Schedules MW * (LMPB - LMPA) $$$ (Later) Bilateral data (Financial) 1st Settlement at DA LMP Prices Buy and Sell Energy DA (at DA LMPs) 21

22. PJM/MISO Use A “2-Settlement” System • A party that schedules (or buys/sells) in the Day-ahead (DA) market is in the 1st settlement: • Energy spot sales and purchases at DA spot prices = LMPDA • Pays for spot transmission at DA transmission usage prices • Usage charge = MW times (LMPsink – LMPsource) • FTR Credit = MWFTRs times (LMPFTR Sink – LMPFTR Source) • So . . . If FTRs match the actual schedule, the FTR credits effectively “hedge” (offset) the transmission usage charge. • A party that deviates from its day-ahead schedules in real time is in the 2nd Settlement: • Settles the deviations at the real-time spot prices = LMPRT 22

23. Real-Time Market = Real-Time Dispatch Deviations From DA Settled at Real Time Prices RTO RT Functions Outcomes Inputs Generator Offers Reliably Serve All Loads Reserves Co-Optimized Load Bids RT Regional Security- Constrained Economic Dispatch Real-time Schedules Self Schedules Hour-ahead Import/Export Settle DA v RT Deviations (at RT LMPs) Calculate RT LMPs Day-Ahead Schedules $$$ Pay Usage for RT Schedules MW * (LMPB - LMPA) 2nd Settlement at RT LMP Prices (Later) Buy and Sell Energy RT (at RT LMPs) $ Bilateral data (Financial) 23 Uplift

24. Interim Coordination Between RTOs Can Partly Reconfigure RTO Boundaries MISO PJM (1) MISO/PJM coordinate flows between them (2) PJM responsible for redispatch for some MISO transmission limits affected more by PJM generation and flows (3) MISO responsible for redispatch for some PJM Tx limits . . . (4) Substitutes more efficient inter-regional redispatch for TLRs 24

25. Future Coordination Between RTO Markets Can Create Joint/Common Market MISO PJM (1) MISO & PJM exchange data on constraints, bids, LMP prices (2) MISO & PJM readjust their respective dispatches (3) MISO & PJM exchange data again, etc. (4) Iterations lead to optimized inter-regional dispatch and prices (5) Forms basis for joint/common market = one unified dispatch 25

26. How RTOs Accommodate • Traditional Utility Service • Merchant Generation • Wind/Renewables • Demand Response • Retail Choice • Carbon Reduction Policies 26

27. RTOs with These Core Features Support Reliability, Renewables, DR and Contracts RTO Functions Market Support Market Inputs Ensure Reliability Reliably Serve All Loads Generator Offers Reserves Cover Imbalances Co-Optimized Real-Time Balancing Regional Security- Constrained Economic Dispatch Load Bids Buy and Sell Spot Energy Contract or Spot Prices Bilateral Schedules Transmission Usage Charge (LMPB - LMPA) Congestion Redispatch (In lieu of TLR) Contracts Calculate Dispatch Prices (LMP) Financially Firm Tx (LMPB - LMPA) Self Schedules Allocate & Auction FTRs Efficient Price signals Settlements at Spot Prices $$$ $$$ 27

28. The RTO Structure Readily Accommodates Many Public Policy Options - Ownership • Traditional utility-owned generation • Any State with traditional cost-of-service regulation can continue within the RTO’s regional dispatch. • Regulated utility can self-schedule it’s own plants to meet its own loads. If they have outages, they use spot purchases as backup. • Utilities free to purchase extra power if needed from spot market, or to sell surplus power to spot market (same as “economy sales”). • Retail rates remain under state regulation = cost of service. • Independent power generation • Merchant plants can contract with utilities and schedule with the ISO. • Or they can offer power to the ISO dispatch and sell at spot price. • Generators can cover their imbalances by buying from or selling to spot market. • Doesn’t change state jurisdiction over retail rates. 28

29. The RTO Accommodates . . . Wind Intermittent and Distributed Generation • Intermittent power, e.g., wind • Wind generators don’t have to “schedule” an unpredictable output. • When it generates, the wind generator is contributing to the dispatch, so it receives the spot price (LMP) at its location. • Generators with contracts and scheduled deliveries can cover their imbalances from the ISO spot market. • RTO accepts delivery at the generator’s location; transmission owner provides the interconnection (costs allocated per FERC rules) • Distributed generation • Can be treated same as wind. When it generates, it receives the spot price (LMP) at its location for the MWh it produces. • It can use net metering settlement feature to account for on-site load • Interconnection at the distribution level defined by local utility, and state regulation, just as today. 29

30. The RTO Accommodates . . .Demand-side Response/Real-time Pricing • Customer demand-side response and real-time pricing • RTO spot markets are wholesale; demand side response is either wholesale (by the utility or DR provider) or retail (end-use customers) • Utility/DR provider faces the ISO spot prices as incentives. • End-use customers face retail rates as incentives, but . . . • With real-time pricing, customers can face spot prices as incentives. • Customer sells back its bought energy, at the LMP spot price. • Efficient demand side response reacts to the marginal cost of generation in real time. That’s what the RTO spot price is. 30

31. The RTO Accommodates . . .Retail Choice with Default Supply • ISO spot market supports efficient retail choice and default supply options. • All competitive suppliers and LSEs have open access to grid and the ISO spot market to support their supply contracts. • Competitive suppliers use the spot market to cover their imbalances. • Retailers pay their share of redispatch costs, so allowing retail choice does not shift power or delivery costs from those who shop (commercial/industrial) to those who don’t (residential). • No matter what policy applies, the RTO handles grid reliability and wholesale spot market, leaving states free to regulate retail rates and service. Retail choice is a state option, not a federal mandate. The RTO/ISO is neutral on these policy choices. 31

32. S p1 p2 P D Genco Marketer Marketer Retailer State Default Supply Auctions(Some Retail Choice States Only) Auction Bidders Auction Winners Sign Contracts with Utility Declining Clock Auction Picks Lowest Cost Suppliers 1-yr Contract For med C&I 2-yr Contract For small C&I 3-yr Contract For Residential Auction monitors: -- Independent auctioneer -- State PUC 32

33. To Reduce Carbon Emissions, We Have to Displace the Coal Plants. It Won’t Be Easy. $/MWh These plants not likely to be coal PShortage Shortage hours PPeak Demand Peak hours PShoulder Supply offers POff-peak Off-peak hours Shoulder hours The Coal plants are typically baseload, near the bottom of the dispatch merit order. Without a mandate to retire, you need enough alternatives to push coal plants to the margin. 33

34. How RTOs Provide Open Access To All Parties Without Discrimination 34

35. RTOs with These Core Features Provide Open Access Without Discrimination RTO Functions Market Support Market Inputs Ensure Reliability Reliably Serve All Loads Generator Offers Reserves Cover Imbalances Co-Optimized Real-Time Balancing Regional Security- Constrained Economic Dispatch Load Bids Buy and Sell Spot Energy Contract or Spot Prices Bilateral Schedules Transmission Usage Charge (LMPB - LMPA) Congestion Redispatch (In lieu of TLR) Contracts Calculate Dispatch Prices (LMP) Financially Firm Tx (LMPB - LMPA) Self Schedules Allocate & Auction FTRs Efficient Price signals Settlements at Spot Prices $$$ $$$ 35

36. What Does “Open Access” Mean? • Since 1992, the Federal Power Act requires the FERC to: • Prohibit “undue discrimination” in the way jurisdictional transmission owners make their transmission systems available for use by others. • Promote competition by allowing competing generators to have fair access to the grid. • In Orders 888/889 (1996) FERC translated this statutory mandate into an “Open Access” requirement: • Transmission owners must provide open access to their systems by others in ways that do not unduly discriminate against those users. • Original FERC authority extends only to privately-owned utilities • 2005 Energy Policy Act extends FERC authority to public-owned 36

37. The Golden Rule of “Comparable Access”Grid owners must “Do unto others as . . .” • Under Order 888’s “golden rule” . . . • A transmission owner is required to provide transmission service on its grid to other parties on essentially the same (or “comparable”) basis as the transmission owner provides to itself. • But Order 888 doesn’t really apply this principle . . . • And the Order misunderstood the key features of how the system actually operated, especially the meaning of “available transmission capacity” (ATC). 37

38. Two Basic Problems with FERC’s Approach • 1. It ignores the dispatch: Access to transmission and ATC both depend on how the system operators dispatch the system. Changing dispatch changes ATC. • 2. It ignores the physics: Scheduling along “contract paths” misses how electricity actually flows and causes congestion. Actual flows don’t follow contract paths. • Comments from NERC and utilities on the open access rules pointed out this serious flaw, but FERC ignored the comments in final rules. • To understand these flaws, and correct the problem, FERC needs to acknowledge how the system actually operates. 38

39. 888: Contract Path Scheduling and TLRs • Under Order 888 parties reserve transmission from the grid owner by reserving and paying for a “contract path” with sufficient ATC. • The contract path concept bears little relationship to physical flows. • The contract path is only one of many paths along which electricity actually flows from “source” to “sink” for any given schedule. • Although a contract path may be able to accommodate the flows...other possible paths on which the flows actually travel may not be able to accommodate those flows without overloading. • When this happens, control areas must either “redispatch” or “unschedule” the overloaded lines to keep flows within security limits. • System Operators and Reliability Coordinators use “TLRs” --Transmission Line Loading Relief = curtailment rules set by NERC. 39

40. 100 MW Contract Path Scheduling Is Flawed Because It Ignores the Actual Flows/Physics Schedule with flows along the contract path . . . (not congested) Control Area A Control Area B . . . causes flows on all other paths Loop flows can cause congestion (flows above line limits) anywhere along any path Control Area C Contract path scheduling needs curtailments (TLRs) to “unschedule” the grid to get flows within security limits 40

41. Why Didn’t FERC Require Redispatch? • FERC did not understand transmission service fundamentals: • Dispatch/redispatch is the essential service that provides open access to transmission. • LMP identifies the marginal cost of redispatch. If you can price redispatch service, you can sell it to those who wish to avoid curtailment. • Without this understanding, FERC’s Order 888 said that utilities do not have to offer redispatch to 3rd parties. Instead, utilities may curtail the 3rd party transactions that would otherwise require redispatch. • Of course, without redispatch, operators must use TLR to curtail 3rd party schedules to relieve congestion. 41

42. Can We Still Rely On TLRs For Reliability? • There may have been a time when primary reliance of TLRs was sufficient to ensure reliable inter-control area grid coordination. With hundreds of TLR curtailments being called, that time is past. • TLRs are inadequate because . . . • TLRs can take too long – couldn’t have avoided 2003 blackouts. • TLRs often curtail too many schedules, which leaves the grid under-utilized => creates artificial need for more grid investments • TLR rules don’t cover all flows, so they discriminate • TLRs curtailments ignore economics => higher costs 42

43. RTO Functions Maintain Voltage and Frequency Coordinate Flows Real-Time Balancing Regional Security- Constrained Economic Dispatch Manage Congestion Control Grid Operations Monitor Grid Manage Reserves Keep Flows W/in Limits An RTO Uses a Regional Dispatch To Replace TLR within its Boundaries Coordinate with other RTOs Original Control Area A Original Control Area B TLR Original Control Area D Original Control Area C TLR 43

44. FERC Has Approved Inconsistent Access Rules. Only One Meets the Test of Non-Discrimination • A non-RTO utility -- does not have to offer redispatch service and need not even make its dispatch open to 3rd parties for balancing on the same basis as its own usage. • A utility will always redispatch generation and provide balancing to accommodate its own schedules to serve its own loads. No TLRs. • But it will not redispatch generation to accommodate 3rd party schedules. It uses ATC limits without redispatch to limit access to the grid. It imposes TLRs and charges arbitrary prices for balancing. • This is inherently discriminatory and leads to higher cost (re)dispatch. • An RTO -- offers redispatch service to every user willing to pay the marginal cost of redispatch; it also offers balancing to all at LMP. • It finds the lowest cost redispatch to solve congestion across the region. • It uses LMP to price this redispatch and LMP to price imbalances. • Redispatch marginal costs = the difference in LMP at A and LMP at B. • Every user willing to pay this cost receives redispatch service. No TLR. 44

45. All Previous FERC Orders Fell Short • Order 888/889 – decreed “open access,” but conceptually flawed • Based on contract path scheduling, inconsistent with physics • Ignored access to dispatch, restricted access to balancing • Without LMP, pricing for imbalances was discriminatory • Allowed those with 888-compliant OATTs to continue discrimination • Order 2000 – saw the need for a balancing market, but didn’t clearly connect this to the ISO’s real-time dispatch. The two are the same. • Led to confusion about who/how to provide balancing market • Slowed efforts to create regional dispatch and spot markets • FERC liked LMP at PJM/NY, but didn’t require it in new ISOs • Left confusion over ISO vs Transco, different RTO functions, etc. • “Alliance RTO” was a two-year waste of time, money • FERC’s current Open Access Order 890 is a retreat to the flawed Order 888 model. It will sanction undue discrimination again. 45

46. The RTO Model Works. What Else Works? • RTO Model is based on open access to a regional dispatch and associated spot market, using LMP. • That model provides: • Regional power pool to lower costs, improve reliability • Open access to transmission without discrimination • Reliability supported by the right incentives • Support for markets and traditional cost-of-service regulation • Support for demand response and renewables (wind) • Compatible with physics and how the system actually works . . . • Preserves state jurisdiction at utility/retail level • So far, no one has developed an alternative to this model that meets all of these criteria. 46

47. Extra Slides 47

48. RTO Reliability Functions and Benefits • An RTO that offers a bid-based security-constrained economic dispatch and related monitoring tools across its region can . . . • Internalize regional loop flows and congestion in a large region • Solve congestion region-wide every 5 minutes, before it happens, and solve much of it day ahead with bid-based day-ahead markets • Replace reliance on TLRs within its regional dispatch area • Monitor and react quickly to grid problems on a regional basis • Vastly simplify the coordination needed to ensure regional reliability • Facilitate reserve sharing and reduce operating reserve requirements (diversity is more reliable and saves money) 48

49. Generators Depend on the Highest-Price HoursTo Recover Most of Their Fixed Costs $/MWh Contributions to Fixed Costs PShortage Shortage hours PPeak Supply offers Demand Peak hours PShoulder POff-peak Off-peak hours Shoulder hours Low-price hours barely cover operating costs 49

50. Before RTOs, Many Small Control Areas Made Reliability Harder and More Costly • Actions here affect flows there – it’s one interconnected grid • Coordination is challenging, unforgiving – every operator must do his/her job and let neighbors know quickly about problems. • A single control area’s problems can black out a huge area -- the August 14, 2003 blackout began in Ohio, but quickly spread to NE. • Economic dispatch is balkanized – each local dispatch is less efficient than it could be: we pay more in each area. • Market power is easier to exercise -- the entity that controls the dispatch controls grid access, imbalance pricing, curtailments, etc. 50