Locational Marginal Pricing (LMP)

Locational Marginal Pricing (LMP) was proposed by the CER prior to the introduction of the Single Electricity Market (SEM) but because of reasons of complexity it was not used.

LMP have been adopted by many deregulated electricity markets around the world and operate as follows;

The Grid is represented by a number of geographical nodes, these nodes are assigned by the market operator on where energy is injected (generators) and where it is withdrawn from the network (large consumers or demand centres).

Generators submit a bid before the gate closure, containing time, generation amount and price and their entry point or node to the market operator.

Gate closure is the final time that a generator can make a bid and normally either a full day or one full hour ahead, allowing the market operator to rate all bids. The bid period is half an hour.

The System Operator does this by looking at all nodes in turn and assigning the cheapest electricity to this node until the particular transmission route is full. He then looks at the different transmission routes and takes the next least expensive electricity from different nodes until the forecasted demand is met. The LMP price at this node is then the highest dispatched price and all generators at this node receive this price regardless of earlier lower bids.

However a generator only receives the price on his node. The difference between the two nodal prices is then termed Transmission Usage Charge (TUC) which goes to the network operator (Eirgrid). This price represents the true cost of lost opportunity (power from a cheaper source), congestion and losses on the network.

Because real-time dispatch deviates from the forecasted, a spot market operates to trade excesses or shortfalls through the trading period. “Real-Time LMPs” are then based on these spot prices which are used to adjust the standard LMP payments.

Financial Transmission Rights (FTRs) can be purchased which gives the purchaser the right to transmit electricity on a particular stretch of network (between two nodes) during a particular time. He would then receive any TUC during this period. Power stations (and others) can purchase these rights in advance which brings financial stability into the operation of the network.

The incentive would still remain to use the network in the most efficient way possible, such a power station could well turn down output during a period of congestion and instead receive the lucrative TUC during this period, allowing another Power Station located closer to the load supply instead. Financial Transmission Rights (FTRs) are essentially a hedging mechanism which restores the price certainty to the generators.

Some Comments:

The first thing to note about Locational Marginal Pricing is that it most people don’t understand it properly. I have gone through a number of reports and they all seem to just rehash the examples given on US websites, where this system is in operation.

The concept is actually very easy as explained above, but the implementation quite complex, and most people get caught up and confused focussing on this.

The Irish system was proposed to have 400 nodes, and because electricity follows Kirchoffs laws flowing on parallel paths, it is necessary to compute the electrical paths, points of congestion etc. From this the TUC (Transmission usage charges) and nodal prices are calculated. In computing terms this entails solving a 400 x 400 matrix. (400 x 399 x 398 x 397…combinations) which requires a serious amount of of computing muscle, normally methods such as Runge-Kutta iterations are used.

Undoubtedly simplifications could have been be made, e.g. in Dublin where a number of electrically close generation stations will be lumped together on one node, and nodes at the end of spurs can be simplified, which will improve the calculation efficiency somewhat.

In Operation

For plant operators, it is a very simple system. Prices will very quickly establish a pattern following the load profile throughout the day. Small producers, e.g. Local wind, CHP etc, need only submit a low bid, and will get paid full node price during that time period, giving a strong incentive to build local generation in areas where the grid is weak (e.g. West Coast of Ireland).

Larger Power Stations with long runup times may well decide to submit negative (LMP) prices, so that they can stay running during periods of low demand (perhaps for a few hours), so that they don’t incur the costs of wasted fuel while the machine is brought back on-line. This would bring a serious competitive advantage to flexible, efficient plant.

There is also a direct financial incentive to strengthen weak grid areas (where congestion occurs).