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**Locational Marginal Pricing Overview**

Western Area Power Administration Rocky Mountain Region

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**Locational Marginal Pricing Overview**

4/1/2017 Locational Marginal Pricing Overview Purpose of this Presentation What is Locational Marginal Pricing (LMP)? LMP Basics Unconstrained and Constrained Dispatch Examples LMP Nodal Price Derivation Transmission Congestion Pricing Overview Who Will Be Affected by LMP? Various Arguments Against LMP

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**Purpose of This Presentation**

To acquaint you, the audience, with the basic concepts of LMP. The limited timeframe of this presentation means that it cannot impart enough knowledge to allow the audience to go forth and immediately participate in an LMP market. This presentation is not intended to advocate LMP, nor is it intended to oppose it.

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What is LMP? Technically speaking, LMP is a voluntary, bid-based, security-constrained, economic dispatch market that determines energy and transmission congestion prices at specific points based on marginal generation costs. More simply stated, LMP is a computational model that determines optimal generation unit dispatch as well as locational energy and transmission congestion prices. LMP was developed by Dr. William Hogan, originally for use by the Pennsylvania-New Jersey-Maryland (PJM) ISO.

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**LMP Basics Before we proceed, an explanation of three terms:**

The term “constraint” is used in this presentation to signify an imminent violation of a transmission line’s physical or contractual limitations. “Transmission congestion” is created by a constraint, and the term is used to signify any instance where the lowest-bid generator cannot be dispatched in economic merit order to meet load (and thus another higher-bid generator must be redispatched in out-of-merit order to meet that load). The term “node” is used to signify generation and/or transmission facilities that reside within a given location and have a relatively insignificant impedance. Because the impedance within a node is essentially zero, a generator located in a given node can supply a load at the same node with no impact to the transmission system.

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**LMP Basics Today, integrated utilities:**

4/1/2017 LMP Basics Today, integrated utilities: Determine generation dispatch based on unit availability and operating costs; and Generation is redispatched in order to accommodate transmission constraints. All applicable customers on the grid pay an average energy rate, with no direct assignment of the costs of transmission congestion (i.e., those costs are socialized).

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**LMP Basics LMP is essentially the same as today, but:**

Generator “offer prices” (generally referred to as “bids”) are substituted for “operating cost” to determine unit dispatch. All customers at a specific point on the grid pay the price of the generator that is dispatched to serve the next MW of load at that point, as affected by local bids and transmission congestion. In effect, costs for any transmission congestion are directly assigned to customers within the specific location served by the constrained transmission line(s). An LMP energy market is a spot-based market and does not apply to bilateral contracts (although parties to bilateral contracts will still pay transmission congestion costs).

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LMP Basics LMP’s intended purpose is to determine the delivered energy price at a specific location by calculating and accounting for the relevant energy and transmission congestion prices. Generally, LMP determines an energy price for each electrical node on the grid as well as the transmission congestion price (if any) to serve that node. For the above reason, LMP is often referred to as “nodal pricing”.

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4/1/2017 LMP Basics The locational marginal price at a specific location is the sum of the cost of generating the next MW to supply load at a specific location (based on marginal generation cost), the cost of transmission congestion, and the cost of losses. LMP LMP Generation Marginal Cost Transmission Congestion Cost + + Cost of Losses* = = *For the sake of simplicity, this presentation does not discuss losses or include their costs in its calculations.

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**LMP Basics Node A Node B Load**

Let’s make it simple: Under the Locational Marginal Pricing methodology, the LMP at Node B will be the bid price of the Node A generator that supplies the next MW to serve the load. In this example, G1 can exclusively supply the 100 MW of load, so the LMP at Node B is $20/MWh (which the load pays for its 100 MW). Node A Node B G1 $20/MWh 100 MW 100 MW Load G2 $30/MWh 100 MW 100 MW G3 $20/MWh $50/MWh 100 MW $2,000

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**$3,030 ($1,030 for the next MW of load)**

LMP Basics In this example, the load increases from 100 MW to 101 MW. G1 can no longer exclusively supply the load, so G2 must be dispatched for 1 MW. The LMP at Node B is now $30/MWh. The load now pays $30/MWh for all 101 MW, and both G1 and G2 receive $30/MWh their generated energy. Node A Node B G1 $20/MWh 100 MW 100 MW Load G2 $30/MWh 100 MW 101 MW 1 MW G3 $30/MWh $50/MWh 100 MW $3,030 ($1,030 for the next MW of load)

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**LMP Basics In this example, the load increases from 101 MW to 200 MW.**

What is the LMP at Node B? Node A Node B G1 $20/MWh 100 MW Load G2 $30/MWh 100 MW 200 MW G3 $50/MWh 100 MW

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LMP Basics The LMP at Node B is still $30/MWh, because G1 and G2 can continue to be dispatched to meet the load. The load pays $30/MWh for all 200 MW, and both G1 and G2 continue to receive $30/MWh their generated energy. Node A Node B G1 $20/MWh 100 MW 100 MW Load G2 $30/MWh 100 MW 200 MW 100 MW G3 $30/MWh $50/MWh 100 MW $6,000

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**LMP Basics In this example, the load increases from 200 MW to 201 MW.**

What is the LMP at Node B? Node A Node B G1 $20/MWh 100 MW Load G2 $30/MWh 100 MW 201 MW G3 $50/MWh 100 MW

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**$10,050 ($4,050 for the next MW of load)**

LMP Basics The LMP at Node B is now $50/MWh, because the next MW used to meet the load is generated by G3. The load pays $50/MWh for all 201 MW, and G1, G2, and G3 all receive $50/MWh their generated energy. Node A Node B G1 $20/MWh 100 MW 100 MW Load G2 $30/MWh 100 MW 201 MW 100 MW G3 $50/MWh $50/MWh 100 MW $10,050 ($4,050 for the next MW of load) 1 MW

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**LMP Basics Node A Node B Load**

Under the conditions in the preceding example, if G3’s bid is $100/MWh, the load would pay a total of $20,100 ($14,100 for next MW of load). If G3’s bid is $200/MWh, the load would pay a total of $40,200 ($34,200 for the next MW of load). Node A Node B G1 $20/MWh 100 MW 100 MW Load G2 $30/MWh 100 MW 201 MW 100 MW G3 $?/MWh $?/MWh 100 MW 1 MW

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**Security-Constrained Dispatch Examples**

Before we begin the next set of examples, remember three simple but very important concepts: The LMP at a load is usually, but not always, equal to the bid price of the next MW generated to meet that load. When the transmission system is unconstrained, the LMPs are equal at all nodes to the bid price of the next MW generated to meet that load. Under constrained conditions, LMPs vary by node and can be higher than any generator bid. Note: The load and the generator capabilities and dispatches will vary from example to example, but the generator bid prices remain the same throughout.

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**Security-Constrained Dispatch Examples**

4/1/2017 Security-Constrained Dispatch Examples The following are some relatively simple examples of how LMP prices are calculated from the security-constrained dispatch of a simple transmission system, given the market participant’s bids. Note: All lines have equal impedance. Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 15 MW limit Load

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**Unconstrained Dispatch Examples**

4/1/2017 Unconstrained Dispatch Examples In these next two examples, an increase in load does not cause transmission congestion, so: The lowest-bid generator can be used to meet the load, assuming that the generator is capable of doing so. Redispatch is not necessary to serve the load. All requests for transmission to serve the load from the lowest-bid generator can be accommodated.

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**Unconstrained Dispatch Examples**

4/1/2017 Unconstrained Dispatch Examples If the load on this system were 15 MW at Node C, and Generator B is capable of generating at least 15 MW: Generator B is the exclusive supplier, and flow on the line B-C is 10 MW, below the 15 MW limit, because two-thirds of the energy injected at B flows to C on the B-C line and one-third of the energy flows on the B-A and A-C lines. No resultant congestion, and LMP at the load would be $20/MWh. 15 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A

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**Unconstrained Dispatch Examples**

4/1/2017 Unconstrained Dispatch Examples From the preceding example, if the load increases from 15 MW to 21 MW at Node C, and Generator B’s capability is (for example) limited to 18 MW, Generator A would need to be dispatched for 3 MW: Still no congestion, since total flow across B-C line does not exceed 15 MW. LMP at the load would be $30/MWh, the price of the last MW dispatched. 20 MW 21 MW Note: All lines have equal impedance. 6.7 MW 13.3 MW 20 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 18 MW (+3) 21 MW (+6) Note: All lines have equal impedance. 6 MW 12 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 1 MW 3 MW (+3) 2 MW 1 MW

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**Constrained Dispatch Examples**

4/1/2017 Constrained Dispatch Examples In this next example, the load at Node C increases to the point that supplying it results in a transmission constraint, so: The lowest-bid generator (Generator B) cannot be exclusively used to meet the load, because doing so would violate the constraint. Out-of-merit redispatch of the other, higher-bid generator (Generator A) is necessary to serve the load, and LMP at the load is calculated based on the redispatch costs.

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**Constrained Dispatch Example**

4/1/2017 Constrained Dispatch Example From the preceding example, if the load increases from 21 MW to 30 MW, even if Generator B were capable of exclusively supplying the entire load, it could not do so without exceeding the limit on line B-C. In order to not exceed the constraint, redispatch would need to be performed so that Generator A is incremented by 12 MW (to 15 MW) and Generator B is decremented by 3 MW (to 15 MW). 15 MW (-3) 30 MW (+9) Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5 MW 15 MW (+12) 10 MW 5 MW

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**LMP Price Derivation at Node C**

4/1/2017 LMP Price Derivation at Node C From the preceding example, for every 1 MW of increased load at Node C, in order to not exceed the constraint, Generator A must be incremented 2 MW and Generator B decremented by 1 MW. For this reason, LMP at the load is calculated to be $40/MWh (2MW * $30/MWh - 1MW * $20/MWh), higher than either of the generator bids. The apparently excessive $40/MWh LMP charged to the load includes transmission congestion costs. 14 MW (-1) 31 MW (+1) Note: All lines have equal impedance. 4.67 MW 9.33 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5.67 MW 17 MW (+2) 11.33 MW 5.67 MW

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**LMP Price Derivation at Node A**

4/1/2017 LMP Price Derivation at Node A In this new unconstrained example, a load at Node A would pay an LMP of $20/MWh, since that load can be met by dispatching Generator B. This is due to the fact that Generator B can serve the load at Node A without violating the constraint. 1 MW load MW 15 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 0.67 MW 0.33 MW

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**LMP Price Derivation at Node A**

4/1/2017 LMP Price Derivation at Node A In this new constrained example, a load at Node A would pay an LMP of $30/MWh, since that load can only be met by dispatching Generator A. This is due to the fact that Generator B cannot serve the load at Node A, because part of the energy would flow across line B-C and violate the constraint. 1 MW load 15 MW 30 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5 MW MW 10 MW 5 MW

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**LMP Price Derivation at Node B**

4/1/2017 LMP Price Derivation at Node B In this new unconstrained example, a load at Node B would pay an LMP of $20/MWh, since that load can be met by dispatching Generator B (within the capability of the generator). This LMP would apply even if the system were constrained, and is only subject to the capability limit of Generator B. MW 15 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 1 MW load

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**LMP Price Derivation at Node B**

4/1/2017 LMP Price Derivation at Node B This new “constrained” example assumes that Generator B’s capability is 15 MW. Given that assumption, a load at Node B would pay an LMP of $30/MWh, since that load can only be met by dispatching Generator A. The counterflow from Generator A relieves the constraint, since the flow on Line B-C is now less than the line’s 15 MW limit. 15 MW 30 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 1 MW load 0.67 MW 5 MW MW 10 MW 5 MW 0.33 MW

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**LMP Price Derivation Summary**

4/1/2017 LMP prices are based on actual flow of energy and system operating conditions. The LMP at a load is usually, but not always, equal to the bid price of the next MW generated to meet that load. When the transmission system is unconstrained, the LMPs are equal at all nodes to the bid price of the next MW generated to meet that load. Under constrained conditions, LMPs vary by node and can be higher than any generator bid. Nodal LMPs are a direct function of the system’s constraints.

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**Transmission Congestion Price Overview**

4/1/2017 Transmission Congestion Price Overview In the presence of a constraint, the transmission congestion costs simply reflects the difference of the LMPs between two adjacent nodes. In this example with no constraints and equal nodal LMPs, the load would pay no transmission congestion costs, and holders of Congestion Revenue Rights would receive no revenue (or make any payment). 15 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A

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**Transmission Congestion Price Overview**

4/1/2017 Transmission Congestion Price Overview In this instance, if an entity holds 1 MW of Congestion Revenue Rights on Line A-B, the ITP would pay that entity $10 (1MW * ($30/MWh - $20/MWh)) in transmission congestion costs (assuming the right is an obligation in the correct direction (e.g., Node A to Node B) or an option). 15 MW 30 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5 MW 15 MW 10 MW 5 MW (LMP = $40/MWh)

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**Transmission Congestion Price Overview**

4/1/2017 Transmission Congestion Price Overview If an entity holds 1 MW of Congestion Revenue Rights on Line A-C, the ITP would pay that entity $10 (1MW * ($40/MWh - $30/MWh)) in transmission congestion costs. If an entity holds 1 MW of Congestion Revenue Rights on Line B-C, the ITP would pay that entity $20 (1MW * ($40/MWh - $20/MWh)) in transmission congestion costs. 15 MW 30 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5 MW 15 MW 10 MW 5 MW (LMP = $40/MWh)

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**Transmission Congestion Price Overview**

4/1/2017 Transmission Congestion Price Overview If an entity holds an obligation in the wrong direction across any line (e.g., Node B to Node A), the ITP would charge the right holder the transmission congestion costs across that line. The load itself would receive revenue from (or pay) the transmission congestion if it held Congestion Revenue Rights on any of the lines. 15 MW 30 MW Note: All lines have equal impedance. 5 MW 10 MW 15 MW limit Generator A bid = $30/MWh Generator B bid = $20/MWh C B A 5 MW 15 MW 10 MW 5 MW (LMP = $40/MWh)

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**Who Will Be Affected By LMP?**

If FERC has it’s proposed way, the entire United States will be under an LMP market by October 2004 (through the Standard Market Design NOPR). As it stands now, the California ISO plans to implement an LMP-based market (known as “MD02”) on or around October 2003. Information regarding the ISO’s effort can be found at html

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**Who Will Be Affected By LMP?**

In addition, the Midwest and SPP ISOs plan to jointly implement an LMP-based market on or around December 2003. This implementation will accomplished through adoption and (eventually) seamless integration of the PJM ISO’s LMP-based market. Information regarding this effort (referred to as the “Midwest Common Market Initiative”) can be found at 02_Filing.pdf

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**Various Arguments Against LMP**

Lack of pricing transparency: LMP’s after-the-fact pricing provides no transparency to buyers. High transaction costs: Even relatively small electrical systems such as the PJM or New York ISOs can have thousands of nodes, and the resulting multiple nodal transaction costs can limit market participation and entry. Regulated and unregulated services are needlessly bundled: Under LMP, transmission (a regulated service) is effectively bundled with the generation commodity (unregulated market) in order to derive prices.

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**Various Arguments Against LMP**

LMP improperly allocates risk: The requirement that all successful bidders receive the highest bid price improperly allocates risk and is unnecessarily lucrative to suppliers. LMP is subject to market power abuse: LMP becomes subject to market power abuse if a horizontal concentration in generation is capable of manipulating the exchange price. LMP does not provide incentive to construct generation or transmission: LMP may in certain instances provide incentive to avoid the construction of generation or transmission in order to maximize congestion revenue.

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