For many reasons, electric utilities and power network companies have been forced to restructure their operations from vertically integrated mechanisms to open market systems. With the restructuring and deregulation of the electricity supply industry, the philosophy of operating the system was also changed. The traditional approach was to supply all power demands whenever they occurred, however, the new philosophy states that the system will be most efficient if fluctuations in demand are kept as small as possible. Electricity markets have arisen as a result of the power sector restructuration and power systems’ deregulation. The players participating in the competitive electricity markets must define strategies and take decisions using all the available information and business opportunities to accomplish their goals.
Reliable operation of the electricity system necessitates a perfect balance between supply and demand in real time. This balance is not easy to achieve given that both supply and demand levels can change rapidly and unexpectedly due to many reasons, such as generation unit forced outages, transmission and distribution line outages, and sudden load changes. The electricity system infrastructure is highly capital intensive; demand side (load) response is one of the cheaper resources available for operating the system according to the new philosophy. DR has proved to be a good opportunity for loads to participate in this environment, gaining competitive advantage, and represents significant benefits for the whole electricity market performance. DR programs may produce an increase in power consumption efficiency through active consumer participation, making evident the value that each consumer attributes to his individualized additional demands.
Recent efforts are aiming at improving wholesale markets with more intensive use of DR. This includes, for example, the acceptance of demand bids/offers for ancillary services; the specification by the DR resources of the frequency, duration and the amount of their participation in consumption reduction; and the existence of aggregators that bid into the market on behalf of customers.
This article presents an overview of new flexible resources for operating a reliable system. It starts with defining the Demand Response (DR) and how electricity consumers can be responsive. Highlighting different DR programs follows, including classical, new market-based and dynamic pricing scenarios. Potential cost savings and benefits related to different market components are also discussed.
Demand Response (DR) concepts
DR is a class of demand-side management programs in which utilities offer customers incentives to reduce their demand for electricity during periods of critical system conditions or periods of high market power costs. Interest in DR has increased during the past decade, although these programs have existed for nearly 25 years. Many utilities and independent system operators in deregulated markets have long recognized the benefits of DR. Utilities can purchase load demand from their customers for lower rates than they would pay to provide it, lowering the utility system’s peak demand and help reduce peak wholesale power market prices. In addition, customers can also be asked to reduce load during non-peak periods to help maintain grid reliability, defer or eliminate generation capacity expansion, or defer or eliminate transmission/distribution capacity expansion.
Demand response can be defined as the changes in electricity usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time. Further, DR can be also defined as the incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized. DR includes all intentional electricity consumption pattern modifications by end-use customers that are intended to alter the timing, level of instantaneous demand, or total electricity consumption.
An important advantage of demand response implementation is the postponement of investments in generation resources and transmission/distribution lines. This is highly important when the generation is near its maximum capacity with exponentially increasing generation costs. In these conditions, a small reduction in load will cause a big reduction in generation costs and, therefore, a significant reduction in the price of electricity.
Customer response can be achieved by three actions. The first action is reducing electricity consumption of customers by themselves at peak time when prices are high without altering their usage pattern on normal time. This action involves loss of comfort for a small period temporarily. Temporary change of thermostat settings of heaters or air conditioners is an example. The second action is changing the consumption time of some peak demand operations from peak period to off-peak periods. Changing some household activities to off-peak periods is an example. In this action, there is no loss for residential consumer but losses will be incurred for industrial consumers. The third action of customer response is done by customers who are using onsite generation—customer owned distributed generation. The consumption pattern of these type of customers will not be changed.
Demand response programs can be divided in two wide groups: price-based programs and incentive-based programs.
Price-based demand response program is related with the changes in energy consumption by customers in response to variation in the prices they pay. This group includes Time-Of-Use (TOU), Real Time Pricing (RTP), and Critical-Peak Pricing (CPP) rates. For different hours or time periods, if the price varies significantly, customers can respond with changes in energy use. Response to price-based demand response programs is entirely voluntary. TOU is a rate that includes different prices for usage during different periods, usually defined for periods of 24 hours. This rate reflects the average cost of generating and delivering power during each period. RTP is a rate in which the price of electricity is defined for shorter periods of time, usually one hour, reflecting changes in wholesale price of electricity. Customers usually have the information of prices on a day-head or hour-ahead basis.
CPP is a hybrid of the TOU and RTP programs. The base program is TOU and a much higher peak pricing is used under specified conditions (e.g., when system reliability is compromised or supply costs are very high).
Incentive-based demand response includes programs that give customers incentives which may be fixed or time varying and that are complementary to their electricity rate. These can be established by utilities, load-serving entities, or a regional grid operator. Some of these programs penalize customers that fail the contractual response when a priority specified events are declared. This group includes programs such as Direct Load Control (DLC), Interruptible/Curtailable Service (ICS), Demand Bidding/Buyback (DBB), Emergency Demand Response Program (EDRP), Capacity Market (CM), and Ancillary Services Market (ASM) Programs. As with Direct Load Control programs, customers participating in Interruptible/Curtailable Programs receive upfront incentive payments or rate discounts. Participants are asked to reduce their load to predeﬁned values. Participants who do not respond can face penalties, depending on the program terms and conditions. Demand Bidding (also called Buyback) programs are programs in which consumers bid on speciﬁc load reductions in the electricity wholesale market. A bid is accepted if it is less than the market price. When a bid is accepted, the customer must curtail his load by the amount speciﬁed in the bid or face penalties. On the other hand, in Emergency DR Programs, participating customers are paid incentives for measured load reductions during emergency conditions.
Furthermore, Capacity Market Programs are offered to customers who can commit to providing pre-speciﬁed load reductions when system contingencies arise. Participants usually receive a day-ahead notice of events and are penalized if they do not respond to calls for load reduction. Ancillary services market programs allow customers to bid on load curtailment in the spot market as operating reserve. When bids are accepted, participants are paid the spot market price for committing to be on standby and are paid spot market energy price if load curtailment is required.
DR Measurement and Simulation
Several studies have proved that loads are not rigid, exhibiting elasticity that can be used for mutual benefits of power systems and consumers. Changes in electricity price over time and incentive payments give place to increased demand flexibility as end-use customers intentionally modify their electricity consumption patterns as a response to exterior stimulus. DR can be contracted over longer or shorter periods either as result of its inclusion in capacity markets or directly through bilateral contracts.
Price elasticity is a measure used in economics to evaluate the responsiveness of the demanded quantity of a good or service to a change in its price, or the percentage change in quantity demanded on response to a one per cent change in price. In what concerns electric loads, price elasticity is a normalized measure of the intensity of how usage of electricity changes when its price changes by one per cent. In the opposite way, demand elasticity is a measure of how price changes when usage of electricity changes.
In order to ensure the effective participation of the customers in the DR program, a suitable economic load model needs to be developed based on the change of customers’ power consumption with the change of electricity prices, benefits, and penalties applied to the customers. In general, the load demand of customers who participate in the DR programs is inversely proportional with the electricity price as shown in Figure 2.
Demand-price elasticity is defined as the ratio of rate of change of demand to the rate of change of price as follows.
where Î is the elasticity, qo is the demand at price po for a given equilibrium point, and ∆Demand is the change of demand due to the change of price of ∆Price.
The elasticity of a substitution measures the rate at which the customer substitutes off-peak electricity consumption for peak usage in response to a change in the ratio of peak to off-peak prices. This kind of elasticity is important in TOU and CPP pricing programs. The elasticity is divided into self-elasticity and cross-elasticity. Self-elasticity measures the demand reduction in a certain time interval due to the price of that interval. Cross elasticity measures the effect of the price of a certain time interval on electricity consumption during another interval.
As Figure 3. suggests, elasticity is used in conjunction with expected price to modify expected demand; consequently, demand and prices will be reduced if prices are above the equilibrium point (po, qo); see Figure 2. The equilibrium point is defined as price and demand of the normal case. In this analysis, one equilibrium point is assumed for each period.
In this article, a single-sided uniform market price is considered in which the supply-side submits bids for supplying power to the market operator when the market operator has a forecast of demand. These bids reflect generator cost functions. The operator announces the expected prices for the next 24 hours. These prices act as guidelines for customers to respond to that in real time, depending on their elasticity and expected prices. This DR is very beneficial as it can reduce market prices as well as costs. The process used for simulating DR is shown in Figure 4.
Optimal Power Flow formulation
In OPF, the values of some or all of the control variables need to be found to optimise (minimise or maximize) a predefined objective. It is important that the proper problem definition with clearly stated objectives be given at the onset. The quality of the solution depends on the accuracy of the model studied. Objectives must be modelled with its practicality with possible solutions. Objective function takes various forms such as fuel cost, transmission losses and reactive source allocation. Usually the objective function of interest is the minimisation of total production cost of scheduled generating units. This is mostly used as it reflects current economic dispatch practice and importantly cost related aspect is always ranked high among operational requirements in Power Systems. OPF aims to optimise a certain objective, subject to the network power flow equations and system and equipment operating limits.
For Optimal Power Flow (OPF) simulations, we use MATPOWER a MATLAB Power System Simulation Package. A common objective function used in OPF studies is the minimization of generation costs.
The objective function based on generation operating cost can be expressed as,
where J is the total generation costs; Ci(Pi) is the cost function of generator i; Pi is the power output of generator i, and NG is the set of all generating units including the generator on the slack bus. Generators are assumed to be bidding their true cost of generation.
The minimization objective function has the following constraints: Network equations –
where Vi is the voltage at bus i; d is the angle associated with the voltage at relevant buses; Yi,j is the element of the bus admittance matrix; q_(i,j) is the angle associated with Yi,j; Pi and Qi are real and reactive power generation at bus i, respectively. PDi and QDi are real and reactive power demand at bus i, respectively. NL is the number of load buses.
PiMin and PiMax are the lower and upper limits on real power generation and QiMin and QiMax are the lower and upper limits on reactive generation from bus i.
Bus Voltage Limits
This constraint ensures that the voltages at different buses in the system are maintained at specified levels.
The generator bus voltages are maintained at a fixed level. Voltage level at a load bus is maintained within a specified upper limit ViMax and a lower limit ViMin
There are two types of market price formulations: the Locational Marginal Prices (LMP) and the Uniform Market Price (UMP). The Locational Marginal Pricing (LMP) mechanism is one of the most commonly employed tools for market settlement in the deregulated power system environment. The LMP at a bus signifies the cost of supplying the next increment of load at that bus. It is the sum of supplying energy marginal cost, cost of losses due to the increment and transmission congestion cost, if any, arising from the increment. The market price at each bus is represented by the Lagrangian multiplier li of the real power balance constraint at that bus.
In an UMP formulation, the market price is the highest value of the bus incremental cost obtained by solving the above model:
where r represents the uniform electricity market price; li is the incremental cost of generation at bus i, and N is the number of buses in the system.
…to be continued
Arul Doss Adaikalam is from T.J.S Engineering College, Chennai, Tamil Nadu, India
C. K. Babulal is from Thiagarajar College of Engineering, Madurai, Tamil Nadu, India