Locational marginal pricing is a way for wholesale electric energy prices to reflect the value of electric energy at different locations, accounting for the patterns of load, generation, and the physical limits of the transmission system. In New England, wholesale electricity prices are identified at over 1,000 pricing nodes (i.e., locations) on the bulk power grid that include individual points on the transmission system, load zones (i.e., aggregations of pricing nodes), external nodes where the ISO New England transmission system interconnects with a neighboring region, and the Hub.
The Hub is a collection of locations intended to represent an uncongested price for electric energy, facilitate electric energy trading, and enhance transparency and liquidity in the marketplace. See the set of nodes that constitute the Hub.
An LMP is the price for electric energy at each load zone, external interface with neighboring regions, and the Hub that reflects (1) the operating characteristics of, and (2) the major constraints on, the New England transmission system at each area, as well as (3) the losses resulting from physical limits of the transmission system. LMPs are calculated every five minutes. The LMP at a load-zone is a weighted average of all the nodes within the load zone.
If the system were entirely unconstrained and had no losses, all LMPs would be the same, reflecting only the cost of serving the next increment of load. The generator with the lowest-cost energy offer available would serve that incremental megawatt of load, and electric energy from that generator would be able to flow to any node on the transmission system. LMPs differ generally among locations because transmission and reserve constraints prevent the next-cheapest megawatt (MW) of electric energy from reaching all locations of the grid. Even during periods when the cheapest megawatt can reach all locations, the marginal cost of physical losses will result in different LMPs across the system.
The ISO uses locational marginal pricing to accomplish the following tasks:
Market Rule 1, Section III.2, describes the LMP calculation:
The ISO calculates day-ahead and real-time locational marginal prices (as well as real-time reserve clearing prices) using data for the following elements:
While the day-ahead and real-time LMPs are based on the same basic calculation, they differ in several ways. Day-ahead LMPs are calculated for each hour of the Day-Ahead Energy Market (using day-ahead nodal prices), and real-time LMPs are calculated every five minutes during the operating day for the Real-Time Energy Market (using real-time nodal prices). Another difference is that the real-time LMP jointly optimizes the dispatch of electric energy and reserves. Other differences are described below.
The day-ahead LMP calculation uses the energy offers and bids scheduled in the Day-Ahead Energy Market from all market participants for all applicable locations. The calculation of a day-ahead nodal price is based on least-cost, security-constrained unit commitment and dispatch; model flows; system conditions resulting from the market participants’ load specifications; the resources’ supply offers and demand bids; incremental (virtual) offers; decremental (virtual) bids; and external transactions submitted to the ISO and scheduled in the Day-Ahead Energy Market.
The calculation applies a linear-optimization method to minimize the costs of energy, congestion, and transmission losses, given the scheduled system conditions, scheduled transmission outages, and any transmission limitations that may exist. This calculation sums the following elements to derive the cost for each resource associated with an eligible energy offer or bid to serve an increment of load at each node and external node:
The energy offer or offers and energy bid or bids that can serve an increment of load at a node or external node at the lowest cost, calculated in this manner, determines the day-ahead locational marginal price at that node.
The calculation of the real-time LMPs (and real-time reserve clearing prices) uses each market participant’s energy offer from a generating resource, the purchase of an external transaction resource, and a dispatchable asset-related demand resource following economic dispatch instructions. This calculation is based on a jointly optimized economic dispatch of energy and the designation of operating reserve using the prices of the energy offers and bids and Reserve-Constraint Penalty Factors (i.e., administratively set limits on redispatch costs that the system will incur to meet reserve constraints), when applicable.
Like the calculation of the day-ahead nodal price, the calculation of the real-time nodal price uses an incremental linear-optimization method to minimize the costs for energy, congestion, and transmission losses. But this calculation also minimizes the costs for operating reserve and it accounts for actual, not scheduled, system conditions, plus the set of energy offers and bids and any existing binding transmission and operating-reserve constraints. This real-time nodal price calculation sums the following elements to derive the cost for each available generating resource, external transaction purchase, and dispatchable asset-related demand resource with an eligible energy offer to serve an increment of load at each node and external node:
The energy offer or offers and energy bid or bids that can jointly serve an increment of load and an increment of operating-reserve requirement at a location at the lowest cost—as calculated in this manner—determines the real-time locational marginal price at that node or external node.