LMP Implementation in New England
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- Gregory Lyons
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1 IEEE PES General Meeting, Montreal Eugene Litvinov June, ISO New England Inc. 1
2 New England s Electric Power System 14 million people; 6.5 million households and businesses 350+ generators 8,000+ miles of transmission lines 12 interconnections to neighboring systems 32,000 MW total supply All-time peak demand: ~26,885 MW on 7/27/05 Eight (8) Pricing Zones 320 mi. 520 km 400 mi. 650 km 2006 ISO New England Inc. 2
3 Central Dispatch by ISO New England Dispatch New England s resources as a single system to: Maintain reliability throughout the region Minimize cost of electric production in New England Adhere to national, regional, and local operating procedures and policies VELCO (2005) Maine Local control centers operated by Transmission Owners Electronic Dispatch System communicates directly with generators NH REMVEC CONVEX NSTAR (2005) 2006 ISO New England Inc. 3
4 Congestion Patterns in the ISO New England 2006 ISO New England Inc. 4
5 LMP Pattern 2006 ISO New England Inc. 5
6 New England Wholesale Electricity Markets Two-Settlement Energy Market DA and RT Locational Marginal Pricing (LMP) LMP in over 900 locations Enhanced Risk Management Tools Bilateral Transaction Virtual bidding Financial Transmission Rights (FTRs) Capacity Market Ancillary Services Market Forward Reserve Regulation 2006 ISO New England Inc. 6
7 Congestion Management System Location-based marginal pricing Marginal loss pricing Ex-post real time pricing Centralized security constrained unit commitment Financial Transmission Rights Market software vendor: Areva 2006 ISO New England Inc. 7
8 Challenges in LMP Implementation Commercial network model maintenance LMP components and their interpretation Reference (slack) bus use and selection Marginal loss pricing and surplus allocation Consistent ex-post pricing Understanding very high prices and very low negative prices The effect of self-scheduling and fixed load bidding The effect and usage of virtual offers and bids Handling infeasibilities Pricing out of market actions Pricing under excess generation conditions, etc ISO New England Inc. 8
9 Commercial Network Model Unlike bus/branch network model that is being used in advanced network applications, the objective of the commercial network model is to provide pricing locations for trading. Locations provide points in the system where participants submit offers and bids, markets settle, and LMPs are calculated. Location is not necessarily a physical point in the electrical network model ISO New England Inc. 9
10 Locations Node corresponds to a physical bus or collection of buses within the network Load zone aggregation of nodes. Zonal price is the load-weighted average of the prices of all nodes in the zone Hub representative selection of nodes to facilitate long term commercial energy trading. The hub price is a simple average of LMPs at all hub locations. External/proxy node location that serves as a proxy for trading between ISO New England (ISO NE) area and its neighbors 2006 ISO New England Inc. 10
11 Network Model Hierarchy SCADA One-line (Nodes) TP AC Bus/Branch (Buses) Linearization DC Bus/Branch (Buses) SCED Commercial (Private p-nodes) Agregation Commercial (Locations) SE RQM AC Power Flow (Buses) Settlements (MD/Locations) 2006 ISO New England Inc. 11
12 LMP Components λ = λ LF λ S µ, i i K + k= 1 ik k Congestion Component Loss Component Energy Component The energy component is the same for all locations and equals to the system balance shadow price. Congestion components equal to zero for all locations if there are no binding constraints all k =0. The loss component is the marginal cost of additional losses caused by supplying an increment of load at the location ISO New England Inc. 12
13 LMP and the Reference Bus LMPs will not change if we move the reference bus from one location to another. However, all three components are dependent on the selection of the reference bus (due to the dependency of the sensitivities on the location of the reference bus) ISO New England Inc. 13
14 LMP Components The dependency of components on the selection of the reference bus proves that the value of each component by itself does not mean much only the differences may have some meaning if used accurately. The only reason we need LMP components is the need to use them for FTRs and split congestion cost from energy. Energy component is not the price of energy without congestion and losses 2006 ISO New England Inc. 14
15 LMP Components Settlement System wide, generators are being paid: λ P = ( λ LF λ + S µ ) P. i i i ik k i i i k System wide, loads pay: λ L = ( λ LF λ + S µ ) L. i i i ik k i i i k Total revenue: λ ( P L ) + λ LF ( P L ) µ ( P L ) S i i i i i k i i ik i i k i λ Loss + λ Loss µ T max marg k k k ISO New England Inc. 15
16 LMP Components Settlement Loss revenue: Loss Re v = λ ( Loss Loss). marg Congestion revenue: Cong v T max Re = µ k k. k Loss is a value based on the Revenue Quality Metering ISO New England Inc. 16
17 Reference at T 2006 ISO New England Inc. 17
18 Reference at P 2006 ISO New England Inc. 18
19 Reference at Q 2006 ISO New England Inc. 19
20 Settlement Loads implicitly pay for physical losses just due to the fact that generation is higher than load by the amount of physical losses, so this is coming out of the surplus. The surplus of money has nothing to do with the payment for losses it is the result of marginal pricing. If we accept the principles of marginal pricing, the surplus is inevitable, both with respect to congestion and losses ISO New England Inc. 20
21 Who is Paying for Losses? Looking at the LMPs, it is impossible to tell which part is payment for marginal losses and which is payment for energy LMP is the price of energy at a location. As soon as we want to split LMPs into components in order to separate energy, congestion and marginal loss money, we have to arbitrarily define a reference (slack) bus. Depending on the location of the reference bus, the values of different revenue buckets will change, even though the total will not. The dependency of the revenue split on the selection of the market reference may create problems in agreeing on the location of the reference among stakeholders. FTR payments also change with the change of slack bus 2006 ISO New England Inc. 21
22 Modeling Losses in the Lossless System LP methodology uses DC network model to calculate LMPs. In the DC model, there are no losses in the transmission lines, but sum of all generation is greater than sum of all loads by the amount of losses. This brings up an issue: if there are no losses in the network, where to put losses to keep the balance? 2006 ISO New England Inc. 22
23 Losses in the DC Model In a traditional approach, slack bus always makes up for losses, which means that all system losses are withdrawn at one bus. This may significantly distort the power flow in the network and, as a result, change LMPs. The slack bus that has been selected as a reference for shift factors determines the location of the losses in the network ISO New England Inc. 23
24 Two Bus LP Formulation 1 Transfer Limit = 150 MW 2 P 2 $10/MWh P 12 P 1 $5/MWh L 1 =50MW L 2 =250MW LP1: Min 5P + 10P S.T. 1 2 P1 + P2 L1 L2 Loss = 0; Loss = lf1( P1 L1 ) + lf2( P2 L2 ); sf ( P L ) + sf ( P L ) ISO New England Inc. 24
25 Two Bus LP Formulation with Distributed Losses LP2: Min 5P + 10P 1 2 S.T. P1 + P2 L1 L2 Loss = 0; Loss = lf ( P L ) + lf ( P L ); sf ( P L d Loss) + sf ( P L d Loss) ISO New England Inc. 25
26 Distributed Slack The reference for shift and loss factors does not have to be located at a particular physical bus. If we select a distributed slack, we assign participating factors for each bus to cover imbalance in the system. Let us use distributed bus with the load-weighted participating factors. Let us distribute losses among all load buses as well ISO New England Inc. 26
27 Distributed Slack The results can be presented as follows: 205MW $5/MWh $10/MWh 1 Transfer Limit = 150 MW MW 126 MW L 1 =50 MW 5 MW 26MW L 2 =250 MW $9.17/MWh Distributed Slack Loss=31 MW 2006 ISO New England Inc. 27
28 LMP with Distributed Slack When distributed slack participating factors are selected the same as loss distribution factors: d λ + d λ = λ This means that the energy component will be the weighted average of all load locational prices. For the two bus example: λ = 1/ / 6 10 = $ / MWh ISO New England Inc. 28
29 5 Bus Model: Distributed Slack $20/MWh E Transfer Limit = 240 MW $33.87/MWh D Sundance Brighton 463 MW $23.07/MWh Alta 110 MW A 223 MW 240 MW Park City 100 MW Distributed Slack $28.58/MWh 246 MW 300 MW B 187 MW $31.12/MWh 7 MW 7 MW 61 MW 300 MW C 9 MW $30/MWh 23 MW 19 MW Solitude 349 MW 0 MW 400 MW λ = = $31.12 / MWh 2006 ISO New England Inc. 29
30 Loss Model with Loss Distribution With the appropriate and consistent loss distribution, the selection of the slack bus/market reference is not important. Under this design, with the change of the slack bus, LMPs do not change. Moreover, the congestion component and the sum of energy and loss components stay the same. Loss component of the LMP is never used by itself in settlements. Even for analysis, only differences of components between locations make sense to look at ISO New England Inc. 30
31 Operations. Major Components FTR Unit Commitment SCUC SCED SFT SCED Real Time Contingency Analysis State Estimator RT LMP Calculator Network Model SCADA EMS FTR - Financial Transmission Rights SCED - Securuity Constrained Economic Dispatch SFT - Simultaneous Feasibility Test SCUC - Security Constrained Unit Commitment EMS - Energy Management System 2006 ISO New England Inc. 31
32 Daily Schedules Day Ahead Scheduling and Pricing Supply Offers Demand Bids UC SCUC Virtual Offers & Bids Unit Schedules LMPs Binding Constraints DA Publishing Outage Scheduler Constraint Manager Generic Constrraints Hourly Schedules ED Generic Constraints Security Analysis Unit Schedules External Transaction Schedules External Transactions 2006 ISO New England Inc. 32
33 DDP NDR Unit Data NDR Constraints Real Time Dispatch EMS Dispatch RTCA CD-ED VSTLF ED e-d DE LMPC LMPs Publishing 2006 ISO New England Inc. 33 Unit Availability Reserve & AGC Requirements Unit Offers SE Security Constraints TTCs 5-min Load Forecast Hourly Targets from Hour Ahead DDP NDR Unit Data Unit Output
34 New Reserve Market Locational Forward reserve market No day ahead market for reserves Not a two-settlement system Real-time co-optimization with no availability bids Three reserve products: TMSR, TMNSR, TMOR Four pricing zones Real time ex-post pricing for co-optimized model very difficult problem Go-live date: October 1, ISO New England Inc. 34
35 Should FTR T- P Holder Be Paid? 2006 ISO New England Inc. 35
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