Primer on LMP

Sponsored by

Paul Arsuaga,
R. W. Beck Inc.

Locational Marginal Pricing (LMP) is a methodology for pricing electricity and managing transmission congestion that has been used by PJM and NY-ISO, and is likely to be adopted across the U.S. by Regional Transmission Organizations (RTOs) such as MISO and CAL-ISO and SeTrans.

This month EL&P invited R.W. Beck to provide answers to commonly asked questions about LMP.

What is Locational Marginal Pricing?

Locational Marginal Pricing is based on the cost of supplying the next megawatt of load at a specific location or node. It takes into account bid prices for generation, the flow of power within the transmission system and power transfer constraints.

What is transmission congestion?

Transmission congestion is a restriction on the flow of power across a transmission system; this power flow, if not restricted, would cause one or more branches within the system to exceed certain technical limits (thermal, voltage, stability or short circuit) under certain conditions.

What is a nodal price in an LMP system?

A nodal price in an LMP system is the incremental increase in total system cost associated with supplying the next increment of load at a specific location or bus. In a constrained system, the next increment of load at a given bus is typically supplied by adjusting the output of more than one generator, each contributing to the load in a ratio dictated by the physical attributes of each system and the location of the bus relative to other elements in the system. Typically, the output of some generators must be decreased when the output of other generators is increased, to prevent the flow on constrained lines from exceeding the constraint.

How is LMP used to manage congestion?

When there is no transmission congestion on an electric system, the cost of serving the next increment of load at any location within the system is the bid price of the next unit in the order of economic dispatch. If there is congestion, the next least-cost generator in the system cannot serve incremental loads at certain locations. As a result, system generation cannot follow economic merit order, and prices at various locations within the system diverge. Generators pay the nodal price and loads pay the nodal price, with the difference being the congestion charge. Owners of firm transmission rights or congestion revenue rights, get a credit equal to the congestion charge which can be used as a financial hedge. Load-serving entities that do not have firm transmission rights must either purchase firm transmission rights or pay the congestion charge. Transactions that cause the most congestion pay the highest price. Therefore, there are incentives to make the most efficient use of the system.

Why are nodal prices in a transmission-constrained system often different throughout a zone?

In a transmission-constrained system, the relative contribution of the generators that serve an increment of load at a bus is dependent on the location of the bus with respect to the generators and other elements in the system. Since the sources of generation and the relative proportion of each generator's contribution to an incremental load can be different at each location, the price of supplying the next increment of load at each node can also be different.

What is nodal vs. hub basis risk?

Most market activity in the U.S. electricity market takes place at trading hubs representing the average prices in certain regions or zones of the electricity market (e.g., COB, Palo Verde, Cinergy, Entergy, etc.), whereas power may be supplied to the grid and loads may be served from the grid at diverse locations within these zones. The nodal price at a particular bus located in a zone such as Entergy may be quite different than the Entergy zone hub price at certain times due to intrazonal transmission congestion. This differential in nodal prices between the trading hub and individual nodes is referred to as "nodal-to-hub basis" differential. It creates a risk that must be considered and taken into account when planning to serve loads or sell generation output at a specific location. For example, the cost of serving a load at a specific node may be higher and more volatile than the electricity price at the nearest hub may indicate. Similarly, failure to recognize nodal-to-hub basis risk may result in over-stating the expected dispatch and associated revenues for a proposed project.

What is the difference between a LMP and a zonal price representation of a power system?

A LMP representation involves modeling the flow of power from resources to loads over multiple branches, maintaining a relationship between branch flows that reflects the impedance of the transmission lines. A limitation on one or more branches can limit a generator's output even though other branches to which the same generator is connected are not fully loaded. In the zonal price representation, which is the traditional method of representing the power system, the electricity market is separated into different zones of load and generation; these are separated by flow gates or interface constraints between the zones. The zonal representation assumes that power can flow freely within the zone such that any resource within the zone can serve an increase in load anywhere within the zone. The LMP representation allows one to model detailed power flows on specific lines and provides individual nodal pricing, whereas the zonal representation does not involve the monitoring of individual lines, and assumes all prices are the same within the zone. LMP is more accurate for projecting the dispatch and revenues of a generating project at a specific location. The disadvantages of the LMP representation are that it requires detailed data inputs not typically available for more than a couple of years, and the results of a model using an LMP representation are very sensitive to assumptions regarding the transmission system configuration. For these reasons, and because LMP models require more time to run, the LMP representation is more applicable for short-term studies of one to three years.

What are the implications of the recent FERC Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) regarding LMP?

The proposed SMD tariff lays out a general framework for a single transmission service ("Network Access Service") and standardizes the operation of all Regional Transmission Organization (RTOs) throughout the U.S. A key component of the SMD tariff is an LMP transmission congestion management system to "provide a mechanism for allocating scarce transmission capacity to those who value it most, while also sending proper price signals to encourage short-term efficiency in the provision of transmission service as well as wholesale energy, and to encourage long-term efficiency in the development of transmission, generation, and demand response infrastructure." If the major elements of the proposed SMD tariff are implemented, the LMP methodology for pricing electricity and managing congestion will be adopted across the U.S.


Paul Arsuaga
R. W. Beck, Inc.
Click here to enlarge image

Arsuaga is a senior director for R. W. Beck Inc. in Orlando, Fla. He can be reached at parsuaga@rwbeck.com or 407-422-4911.

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POWERGRID International

March 2014
Volume 19, Issue 3
1403PG-cover

ELECTRIC LIGHT & POWER

January 2014
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