Locational Marginal Pricing II: Unlocking the Mystery

Locational Marginal Pricing II: Unlocking the Mystery Thomas D. Veselka Argonne National Laboratory Decision and Information Sciences Division Center for Energy, Environmental, and Economic Systems Analysis (CEEESA) Presented at: American Public Power Association (APPA) 2006 Business & Financial Conference Minneapolis, Minnesota Session 34 (PMA) September 19, 2006 1:30-3:00 PM

Locational Marginal Pricing (LMP) Overview Comparison of traditional and competitive power markets Definition of LMP Examples of LMP under unconstrained and constrained dispatch in a simple radial network LMP calculations using Power Transfer Distribution Factors (PTDF) Market participant incentives

Traditional System Operation Is Relatively Straightforward Generator dispatch is based on lowest variable cost Use the generators that are cheapest to operate first Use more expensive generators only as the load increases Adjust generator output to account for transmission constraints System capacity expansion is typically based on a least-cost objective with security constraints (i.e., optimum social benefit) Minimum reserve margin Loss of load probability Charges to consumers are regulated by Public Utility Commissions Determine the company s costs and customer base Allow a rate-of-return

Traditional Unit Dispatch Involves Matching Supply and Demand 140 Generator Production Cost ($/MWh) 120 100 80 For 1 hour Demand Curve (Load) Generation Supply Curve 60 40 20 Consumers energy charge is based on average production costs Generators to be Dispatched 0 0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 Cumulative MW Generators not Dispatched System Marginal Cost Transmission Congestion and Other Factors Will Modify the Choice of Generators to Dispatch

The Competitive Power Market Is Much More Complex Independent System Operator(s) Generation Companies Transmission Company(ies) Distribution Company(ies) Consumers Demand Company(ies) System behavior is a function of numerous independent decisions Emphasis on financial health (individual supply & demand players) Reliability continues to be a high priority (ISO responsibility) Market manipulation concerns and exercise of market power

System Operation Is Much More Complex Generator dispatch is based on power market rules and may include: Generation company (GenCo) energy bids into the pool market Bilateral contracts between buyers and sellers Demand (load) is bid into the market based on price (willingness-to-pay) GenCo bid pricing strategies are designed to support corporate objectives, not optimum social benefit Bids may not necessarily be based on production cost Capacity expansion is also based on strategies that support individual corporate objectives Uncertainty and risks are major concerns

An Important Element of Most Electricity Markets Is the Locational Marginal Price (LMP) The LMP can be viewed in two basic ways: The cost of supplying the last/next MW of load at a given location in the power network The savings of reducing load by 1 MW at a given location in the power network Without transmission congestion The LMP is identical to the system marginal cost when supply bids are equal to production costs The LMP is the same at all busses in the transmission system LMPs are used to account for the effects of transmission congestion Costs vary among busses when power lines constrain the dispatch (ignore loss component) There are typically two types of LMP markets Day-ahead Real-time

Locational Marginal Price Definition The LMP is the cost of supplying the last/next MW of load served at a specific location On the supply-side it is the sum of three components : 1. Marginal cost to purchase generation 2. Cost of transmission congestion 3. Losses Marginal Marginal Transmission Transmission LMP = Bid Bid + Congestion Congestion + Price Price Cost Cost Cost Cost of of Marginal Marginal Losses Losses On the demand-side it is either: 1. The payment or incentive to a consumer to reduce load or 2. The cost of unserved energy LMP is a computational methodology that determines the optimal unit dispatch It computes marginal energy costs at specific locations (busses) It also computes the cost of transmission congestion in the power grid

The Choice of Generators to Dispatch Involves Matching Supply and Demand Based on Bid Prices (not Costs) Generator Bid Price ($/MWh) 160 140 120 100 For 1 hour Price Responsive Demand Curve (Load) Independent System Operator Generation Bid Curve 80 60 40 Generators Accepted 0 0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 Cumulative MW Generators Rejected In the absence of transmission congestion, this is the market price that all consumers pay & all generators are paid Example: Loads On All Lines Are Less Than the Total Transfer Capability Unconstrained Dispatch

In Many Situations, More Expensive Bids Are Dispatched Because of Transmission Congestion Generator Bid Price ($/MWh) 160 140 120 100 For 1 hour Price Responsive Demand Curve (Load) Independent System Operator Generation Bid Curve 80 60 Units Dispatched Out-of-Merit 40 Generators Accepted 0 0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 Cumulative MW Generators Rejected Transmission Congestion and Other Factors Alter the Choice of Generators to Dispatch

LMP Computation Without Transmission Congestion Revenue $1,200 $12/MWh h Production $30/MWh $75/MWh Supply Unit 1 Unit 2 Unit 3 Economic/production cost $1,200 h Assumes Bid Price = Marginal Production Cost GenCo Profit $0.00 50 MWh 50 MWh Demand Consumer 1 50 MWh Consumer 2 50 MWh LMP = $12/MWh Consumer cost GenCo revenue $1,200 Pay $600 Pay $600 Under the LMP market rule, consumers will pay the bid price of the generator that produces the last MWh to serve the load Unit 1 can supply all of the h load, therefore the LMP is $12/MWh Note: Above example assumes that production and load levels are constant over a one-hour time period

A Little More Load May Significantly Increase the LMP $12/MWh h Production $30/MWh 1 MWh Production $75/MWh Supply Unit 1 Unit 2 Unit 3 h 1 MWh 51 MWh 50 MWh Demand Consumer 1 51 MWh Consumer 2 50 MWh LMP = $30/MWh The total consumer load increases from h to 101 MWh Unit 1 can no longer exclusively supply the load Unit 2 must be dispatched at the 1 MWh level The LMP is now $30/MWh All consumers now pay $30/MWh for all 101 MWh and both units 1 and 2 receive $30/MWh for generating electricity Note: Above example assumes that production and load levels are constant over a one-hour time period

A Little More Load May Be Very Costly to Consumers Revenue $3,000 Revenue $30 Note: Assumes that production & load levels are constant over a 1-hour period $12/MWh h Production $30/MWh 1 MWh Production $75/MWh Supply Unit 1 Unit 2 Unit 3 Economic/production cost $1,230 h 1 MWh GenCo Profit $1,800 51 MWh 50 MWh Demand Consumer 1 51 MWh Consumer 2 50 MWh LMP = $30/MWh Consumer cost GenCo revenue $3,030 Pay $1,530 Pay $1,500 Assumes Bid Price = Marginal Production Cost The additional MWh of load has an economic cost of $30 Consumers pay an extra $1,830 for buying one more MWh Consumer 2 did not change its consumption level, but must pay more GenCo energy profits may be used for payments to capital, fixed O&M etc. Unit 1 makes all the profit ($30/MWh-$12/MWh) X Units 2 and 3 make no energy profits

GenCos Have a Financial Incentive to Increase Economic Efficiency Reduced Revenue $3,000 from $12/MWh $10/MWh h Production Revenue $30 Note: Assumes that production and load levels are constant over a 1-hour period $30/MWh 1 MWh Production $75/MWh Supply Unit 1 Unit 2 Unit 3 Economic/production cost $1,030 h 1 MWh GenCo Profit $2,000 51 MWh 50 MWh Demand Consumer 1 51 MWh Consumer 2 50 MWh LMP = $30/MWh Consumer cost GenCo revenue $3,030 Pay $1,530 Pay $1,500 Assumes Bid Price = Marginal Production Cost GenCo energy profits are $200 higher Consumers pay the same amount Additional GenCo energy profits can be used to pay for unit 1 upgrade costs Economic efficiency is increased if production cost savings more than offset capital expenses

What if a GenCo Has Market Power and Influences the LMP? $10/MWh h Production Revenue $50 $50/MWh 1 MWh Production Higher Bid Price Was 30/MWh Note: Assumes that production & load levels are constant over a 1-hour period Revenue $5,000 $75/MWh Supply Unit 1 Unit 2 Unit 3 Economic/production cost $1,030 h 1 MWh GenCo Profit $4,020 51 MWh 50 MWh Demand Consumer 1 51 MWh Consumer 2 50 MWh LMP = $50/MWh Consumer cost GenCo revenue $5,050 Pay $2,550 Pay $2,500 Production costs have not changed GenCos profits are $2,020 above the previous case at the expense of consumers Economic efficiency remains the same - higher compared to the $12/MWh case There is a transfer of wealth from consumers to producers GenCo Financial Motives: Minimize production costs, maximizing accepted bid price

Locational Marginal Price (LMP) Definition The LMP is the cost of supplying the last/next MW of load served at a specific location On the supply-side it is the sum of three components : 1. Marginal cost to purchase generation 2. Cost of transmission congestion 3. Losses Marginal Marginal Transmission Transmission LMP = Bid Bid + Congestion Congestion + Price Price Cost Cost Cost Cost of of Marginal Marginal Losses Losses On the demand-side it is either: 1. The payment or incentive to a consumer to reduce load or 2. The cost of unserved energy LMP is a computational methodology that determines the optimal unit dispatch It computes marginal energy costs at specific locations (busses) It also computes the cost of transmission congestion in the power grid

Transmission System Limits and Congestion Transmission lines have physical limits and may also have contractual constraints Power flows down the path of least resistance Analogy: water flowing through a network of pipes Transmission congestion is created by one or more binding line constraints The lowest-bid generator cannot be dispatched in bid-price order to meet load Another higher-bid generator must be re-dispatched out of the bid merit order to meet that load

Dispatch with Loads of 250 MW without Congestion Radial Network h Production 30 $/MWh LMP = 75 $/MWh @ all locations 100 h Production 10 $/MWh 50 100 Demand 150 MWh 50 MWh Production 50 GenCo Profit $11,000 75 $/MWh Price setter 50 Economic/production cost $7,750 Demand h Consumer cost GenCo revenue $18,750 Assumes Bid Price = Marginal Production Cost Note: Above example assumes that production and load levels are constant over a one-hour time period

Dispatch with Loads of 250 MW with Congestion Radial Network 75 MWh Production 30 $/MWh 75 MWh Production 75 $/MWh Price setter Price setter GenCo Profit Was $11,000 w/cong $2,000 75 75 25 MW transfer limit h Production 10 $/MWh 25 Load 50 100 Load 150 MW LMP = 30 $/MWh Congestion Charge 75 $/MWh -30 $/MWh 45 $/MWh LMP = 75 $/MWh Economic/production cost was $7,750 w/congestion $8,875 Economic Cost $1,125 Consumer cost was $18,750 w/cong $12,000 Assumes Bid Price = Marginal Production Cost Note: Above example assumes that production and load levels are constant over a one-hour time period Congestion Charge Amount re-dispatched (MWh) 25 Congestion charge ($/MWh) 45 Congestion payment ($) 1,125 Consumers save $6,750 with congestion

Non-Radial Networks Make LMP Computations More Difficult User specifies the power injection point.5692.1894.7140.2860.0446.1744.0670 Power Transfer Distribution Factors (PTDFs) are based on line reactance & number of circuits.0007.0069.2880.2819.1887.1813.0601 (1) It is a Linear Relationship (Proportionality).1001 (2) Superposition or Additive The power sink is also specified.3881.3705.2415 LMPs Can Be Solved Using a Direct Current (DC) Optimal Power Flow Algorithm

Some LMP Results Can Be Unexpected An LMP at a point can be higher than the highest generator bid price LMPs can be zero or less than zero Lowering a Generation Company bid at one location can increase the LMP at a different location Changing the network configuration (by the ISO) can significantly impact LMPs A very small increase in load in one location can result in a very large (e.g., double) increase in the LMP

LMPs in a Very Simple Non-Radial Grid (Capacity & Costs) Node T1 Cap. 600 MW PC $20/MWh Node S1 Node T3 Cap. 250 MW PC $100/MWh Node S2 500 MW 0.02 500 MW 0.02 50 MW 0.20 125 MW 0.08 125 MW 0.08 Node S3 Node T2 Cap. 200 MW PC $50/MWh Node S4 Node L1 Demand PC = Production Cost ($/MWh) Cap. = Capacity (MW)

LMPs in a Very Simple Non-Radial Grid (PTDF T1 to L1) Source: T1 Sink: L1 Node T1 Cap. 600 MW PC $20/MWh Source Node S1 0.6897 0.1724 Node T3 Cap. 250 MW PC $100/MWh Node S2 0.1379 Node S3 Node T2 Cap. 200 MW PC $50/MWh 0.6897 0.1724 Node S4 Sink Node L1 Demand PC = Production Cost ($/MWh) Cap. = Capacity (MW)

Single Source & Single Sink - Very Simple Non-Radial Grid Cap. 600 MW PC $20/MWh Source T1 GEN X PTDF = Line Flow T1 L1 100 x 0.6897 = 69.0 MW Cap. 250 MW PC $100/MWh Cap. 200 MW PC $50/MWh Demand Sink PC = Production Cost ($/MWh) Cap. = Capacity (MW)

Single Source & Single Sink - Proportionality (350 MW Load) Cap. 600 MW PC $20/MWh T1 GEN X PTDF = Line Flow T1 L1 350 x 0.6897 = 241.4 MW Cap. 250 MW PC $100/MWh Cap. 200 MW PC $50/MWh Demand 350 MW PC = Production Cost ($/MWh) Cap. = Capacity (MW)

Loads Greater than 362.5 MW Will Require T2 To Be Dispatch (PTDF T2 to L1) Source: T2 Sink: L1 0.3448 Node T1 Cap. 600 MW PC $20/MWh Node S1 0.4138 Source Node T3 Cap. 250 MW PC $100/MWh Node S2 0.0690 Node S3 Node T2 Cap. 200 MW PC $50/MWh 0. 3448 0.5862 Node S4 Sink Node L1 PC = Production Cost ($/MWh) Cap. = Capacity (MW)

When T2 Generates Power, T1 Backs Down Generation to Avoid Line Overload -- Superposition (400 MW Load ) Cap. 600 MW PC $20/MWh T1 L1 325 x 0.1379 = 44.82 MW T2 L1 75 x 0.0690 = 5.18 MW Total = 50.0 MW T1 L1 325 x 0.1724 = 56.03 MW T2 L1 75 x -0.4138 = -31.03 MW Total = 25.0 MW Cap. 250 MW PC $100/MWh Cap. 200 MW PC $50/MWh LMP = 80 Highest Accepted Bid = 50$/MWh Demand 400 MW PC = Production Cost ($/MWh) Cap. = Capacity (MW)

LMPs Can Be Approximated by Reducing the Load by 1 MW Cap. 600 MW PC $20/MWh 1 MW More T1 L1 326 x 0.1379 = 44.96 MW T2 L1 73 x 0.0690 = 5.04 MW Total = 50.0 MW Cap. 250 MW PC $100/MWh 2 MW Less Cap. 200 MW PC $50/MWh Load Reduced from 400 MW ($50/MWh x 2) ($20/MWh x 1) = $80/MWh Demand 399 MW PC = Production Cost ($/MWh) Cap. = Capacity (MW)

The LMP at Node S4 Increases when the Bid at T1 Is Lowered (LMP Manipulation at L1 by T1) Cap. 600 MW PC $20/MWh Bid Is Reduced from $20/MWh to $0/MWh Cap. 250 MW PC $100/MWh Cap. 200 MW PC $50/MWh ($50/MWh x 2) ($0/MWh x 1) = $h Demand 400 MW PC = Production Cost ($/MWh) Cap. = Capacity (MW)

The ISO Relieves Congestion by Opening the Congested Line (450 MW Load) Cap. 600 MW PC $20/MWh Cap. 250 MW PC $100/MWh PTDF=0.8 PTDF=0.2 Cap. 200 MW PC $50/MWh PC = Production Cost ($/MWh) Cap. = Capacity (MW) Demand 450 MW

Actual Power System Operation Is More Complex The North American Power Grid World s Largest Machine Red indicates areas of high LMPs or load pockets where lower cost power cannot be delivered due to transmission limitations Red = High LMP Blue = Low LMP Blue indicates areas of low LMPs or generator pockets where lower cost power cannot be sent out LMPs are the result of the behavior of numerous independent decisions Source: T. Overbye, UIUC

Examples of Generator Bids in PJM for July 26, 2005 Illustrate Bidding That Goes Beyond Production Cost 1000 8X2D 1,200 2O 800 1,000 Price ($/MW) 600 400 Price ($/MW) 800 600 400 200 200 0 0 10 20 30 40 50 60 Amount (MW) 0 0 2,000 4,000 6,000 8,000 10,000 Amount (MW) GenCo 9O bid unit 8X2D of 48 MW at 800-900 $/MWh On a companywide basis, GenCo 2O bid almost 9,000 MW into the market. Approximately the last 1,000 MW of the company s capacity were bid at prices greater than 600 $/MW. These are actual bids, not model results It is not possible to determine if the bids were accepted Market monitor actions in response to the bids are unknown

PJM Data on LMPs for July 26, 2005 Show the Effects of Generator Bids and Transmission Congestion Example Individual Bus LMPs LMP ($/MW) 1000 900 800 700 600 500 400 Bus BIXBY MOUND HOCKING HOCKING MONTGOME HILLVALL BAKER 300 ComEd Bus and Zone LMPs 200 100 0 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Hour of the Day Selected PJM LMPs 180 LMP ($/MW) 160 140 120 100 80 Lowest Bus - 176 STIL Higest Bus - 389 E RO ComEd Zone 60 40 20 0 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Hour of the Day Selected ComEd LMPs

The EMCAS Model Developed by Argonne Uses Agent Based Modeling to Simulate Possible Market Participant Behavior Decision-making agents Consumers Physical agents Demand companies Generators Generation companies Transmission buses Transmission companies Transmission lines Distribution companies ISOs Regulators

EMCAS Is Used as an Electronic Laboratory Production Cost Bid production cost Physical Withholding Take units out of service Economic Withholding Raise prices Price Probing Combined Strategies Find price levels Price probing and physical withholding Experiments moved from very simple to more complex strategies Production Cost Case used as a benchmark (Base Case) Not intended to imply that any company would attempt market manipulation Only an initial mapping of possible market behaviors

LMPs Increase In the Peak Load Summer Months and Vary Across the State, Even Under Production Cost Bidding January February March April May June July August September October November December LMP Price and Duration: Lower Higher

LMPs Are Significantly Higher When GenCos Engage in Strategic Bidding to Increase Profits January February March April May June July August September October November December LMP Price and Duration: Lower Higher

The Report Is Posted on the Illinois Commerce Commission (ICC) Website http://www.icc.illinois.gov/en/library.aspx?key=electricity&key=report -- Date: 6/13/2006

Conclusion: LMP Markets Need To Be Viewed From Many Different Perspectives Economic efficiency Distribution of economic gains Among suppliers and consumers Geographically and over time Motives and potential behavior of market players Potential market manipulation (when, where, & how often)