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Overview of different electricity markets
Electricity is a commodity that cannot be stored economically in large quantities. Therefore,
generation must equal demand plus energy lost as heat when electricity is transported (transmission
/ grid losses) on an instantaneous basis. Otherwise the grid frequency starts deviating from its
reference value, which can result in a system collapse. The design of electricity markets is adapted to
deal with this particular property of electricity. Different types of electricity markets are arranged in a
sequential order, starting years before the actual delivery and ending after the actual delivery.
Figure 1: Temporal ordering of the different electricity markets (source: KU Leuven Energy Institute)
It is the Transmission System Operator (TSO) who needs to ensure that the instantaneous demand-
supply balance is maintained. Before the actual delivery, the balance responsibility is passed on to
Balance Responsible Parties (BRPs). A BRP is a private legal entity that takes up the responsibility to
compose a balanced portfolio.
Forward and Future Market
The Forward & Future Markets operate from a year or more ahead down until the market closes at a
time defined as Gate Closure when the System Operator takes on the role of residual balancer.
Forwards and futures are contracts for firm delivery of electricity at a certain time in the future for a
price agreed upon today. Futures are standardized contracts that can be further traded on power
exchanges. Forwards are mainly traded bilaterally over-the-counter and are not standardized, giving
more flexibility to the involved parties, and they are usually not further traded.
Different types of electricity markets modelled
using PLEXOS® Integrated Energy Model – The
UK Balancing Market example
Peny Panagiotakopoulou, Senior Power Systems Consultant,
Energy Exemplar Europe
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Day Ahead Market
The Day-Ahead Energy Market (DAM) is a financial market where market participants purchase and
sell energy at financially binding day-ahead prices for the following day. The DAM market is usually
based on the bid (Buy) and offer (Sell) data submitted to the DAM by the market participants.
Day-Ahead markets provide a forward market to hedge against the spot price volatility. The buyers
and sellers can be large energy users (buyers), distribution retailers/utilities (buyers), power plant
owners (sellers), or financial traders (buyers and sellers). Day-Ahead markets are generally used in
conjunction with real-time (spot) markets to balance how market participants deviate from their day-
ahead energy positions.
In the UK electricity is mostly traded through exchanges (APX and N2EX) to match offers and bids of
participants. APX Power UK (established in 2000) offers a market place for integrated trading, clearing
and notification for spot and prompt power contracts and a trading platform for cleared forwards
Intra Day Market
In the Intra-Day Market, electricity is traded on the delivery day itself. The intra-day market enables
market participants to optimise their position and correct their day-ahead nominations due to better
wind forecasts, unexpected power plant outages, etc.
The GB Balancing Market
In the GB Wholesale electricity market, organisations that require electricity for their customers
(Suppliers), enter into contracts with organisations that produce electricity (Generators), sometimes
through intermediaries called Non Physical Traders. These types of organisations are called BSC
Parties. A BSC Party is any company that has signed the Balancing and Settlement Code Framework
Agreement. This includes all licensed electricity companies in Great Britain who are required by their
license obligations to sign the BSC.
Suppliers will calculate the estimated electricity requirements for their portfolio of customers for each
Settlement Period, and they will then enter into contracts with generators in order that their
customers receive the correct quantity of electricity for each Settlement Period.
This forms Forward bilateral contracts & power exchange markets for firm delivery of electricity, which
operate from a year or more ahead down until the market closes at a time defined as Gate Closure
when the System Operator takes on the role of residual balancer.
Due to the fact that electricity cannot be stored, generation must always equal demand plus energy
lost in the form of transmission losses. But, there are several challenges in achieving this, since the
contracts between generators and suppliers do not always completely balance the Transmission
System (i.e. suppliers may not always accurately predict demand; generators may not always be able
to tightly control their generation - intermittent generation or plant tripping off the transmission
system; problems may arise with transmission lines; the market trades in half hour Settlement Periods,
but the Transmission System must balance at every instant).
Where the Transmission System is not balanced it is called Imbalance. The transmission system should
be always balanced, a job that is known as system operation, and is managed by the System Operator
(SO), National Grid in the UK.
In order to balance the Transmission System, the SO needs to know what generators intend to
generate and what suppliers intend to consume for each Settlement Period. The SO needs this
information before the start of the Settlement Period so that it can understand the Transmission
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System imbalance, plan how to balance it and take balancing actions. Therefore, generators and
suppliers submit Physical Notifications (PNs) for each Balancing Mechanism Unit (BMU) to the SO for
each Settlement Period. 1 hour before each Settlement Period the PNs of Parties are frozen. This is
called Gate Closure. At this point the PNs become Final Physical Notifications (FPNs). After Gate
Closure, Parties must try to adhere to the FPNs submitted to the SO. They should only deviate from
their FPN at the instruction of the SO.
Following Gate Closure, the SO is able to evaluate the net imbalance of the Transmission System; also
called the Transmission System length. A ‘Long' Transmission System is the one where there is more
generation than demand, whereas a ‘Short' Transmission System is the one where there is more
demand than generation.
Parties submit notices, called Bids and Offers, telling the SO how much it would cost for them to
deviate from their Final Physical Notification. The SO assesses all the Bids and Offers for each
Settlement Period and chooses the ones that best satisfy the balancing requirements of the
The SO is trying to balance the Transmission System as efficiently as possible. So ideally the SO would
choose the cheapest balancing action, one after the other. Nevertheless, this is not always possible
since the SO should also consider any technical limitations of the Power Station (ability to increase or
decrease generation/demand quickly enough to meet the requirement), and any technical limitations
of the Transmission System (ability of the generation/demand to be transmitted to the part of the
Transmission System where it is needed).
Balancing Markets modelled in PLEXOS®
In a Balancing Market in PLEXOS®, generators define their dispatch level from a day-ahead market
using the properties Generator Offer Base/ Price. The goal of the balancing process is then to select
optimal increments (‘incr’) and decrements (‘decr’) around these day-ahead positions to meet
deviations in the real-time load. The input pairs Generator [Offer Quantity] and [Offer Price] are used
to define the ‘incr’ and ‘decr’ offers.
Positive quantities are interpreted as offers to increment the generator's dispatch above the base
quantity, while negative quantities are interpreted as offers to decrement the generator's dispatch.
The impact on the system is the product of the ‘incr’/’decr’ and the offer price, thus an ‘incr’ with a
positive price increases cost accordingly and a ‘decr’ with a positive offer price, decreases system cost.
Balancing Market modelling in PLEXOS® is usually undertaken in two stages.
At Stage 1 the Day-ahead market is modelled using hourly time intervals, while the results for
generation, un-dispatched capacity, available capacity, SRMC, etc. of the generating units are saved
in Data Files. Stage 2 then follows, which is considering the Real-time market, and uses finer
resolution, i.e. time intervals of 30 or 15mins. In addition, the previously saved results of Stage 1, as
well as a new forecast of demand and/ or renewables are used by PLEXOS, in order to optimise the
balancing of units.
The solution of stage 1 model (i.e. ‘Base 2013-2014 DA’ in this case study) can act as input for the
subsequent stage 2 model. The data are passed between simulations simply be enabling the option to
Write Flat Files in the Report object.
In the Day-ahead model the user can select all the outputs that will act as inputs to the Real-time
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model to be written in flat files, and these will then be written into a folder structure. These files can
then be referenced in order to be used as inputs for the subsequent stage 2 model (i.e. ‘Base 2013-
2014 RT’ in this case study).
Figure 2: Data File objects used in the PLEXOS® RT model
The Day-ahead GB market model can be defined in PLEXOS as a common unit commitment and
economic dispatch problem, where the objective function would be to minimize the total system