Demand Side Management

Demand side management (DSM) is the planning, implementation and monitoring of utility activities that encourage consumers to change the amount and time pattern of their electricity use, so that the load curve takes a desired shape. It works on the consumer side of the meter instead of building new generation.

Objectives

• Reduce peak demand and defer new power plants and lines.
• Improve load factor and use of existing plant.
• Reduce cost of supply and consumer bills; reduce losses and emissions.

Load-shape techniques (the six basic DSM objectives)

 Peak clipping     Valley filling    Load shifting
  __/--\__          __/~~\__          __/--\__
 /  cut   \        /fill    \        /  move  \
            Strategic conservation  Strategic load growth
            Flexible load shape

1. Peak clipping: reduce load during peak hours, e.g. utility switching off water heaters or pumps by direct load control.
2. Valley filling: build up load in off-peak hours, e.g. EV charging, storage heating, irrigation pumping at night.
3. Load shifting: move loads from peak to off-peak time, e.g. industries running heavy furnaces or crushers at night under time-of-day tariff.
4. Strategic conservation: reduce overall energy use by efficient equipment, e.g. LED lamps, efficient motors, insulation.
5. Strategic load growth: planned increase in sales, e.g. electric cooking, electric vehicles, replacing diesel and LPG with hydro power.
6. Flexible load shape: interruptible/curtailable supply contracts; consumers accept limited reliability in return for lower tariffs.

Means of achieving effective DSM

1. Tariff-based methods: time-of-day (ToD) tariff, seasonal tariff, demand charges in kVA, pf penalties, real-time pricing.
2. Energy efficiency programmes: efficient lighting (CFL to LED), high-efficiency motors and VFDs, energy audits, appliance labelling.
3. Direct load control and interruptible loads: utility remotely switches selected loads during peaks.
4. Demand response and smart metering: consumers reduce load on signals or price; smart meters and automation make it easy.
5. Power factor correction: capacitors reduce kVA demand and losses.
6. Energy storage: batteries, thermal storage and pumped storage charge off-peak and discharge at peak.
7. Consumer awareness and incentives: rebates, subsidies and education campaigns.

Effective DSM needs good load research, attractive incentives, reliable metering and monitoring of results.

The capacitor kVAR is fixed by the half-load condition and then stays connected at full load and at no load.

Input power and reactive power of the motor

Full load: output 35 kW, $\eta = 0.9$, pf 0.9

$$\begin{aligned} P_{FL} &= \frac{35}{0.9} = 38.89\ \text{kW} \\ Q_{FL} &= P_{FL}\tan\phi = 38.89 \times \tan(\cos^{-1}0.9) = 38.89 \times 0.4843 = 18.83\ \text{kVAR} \end{aligned}$$

Half load: output 17.5 kW, $\eta = 0.7$, pf 0.6

$$\begin{aligned} P_{HL} &= \frac{17.5}{0.7} = 25\ \text{kW} \\ Q_{HL} &= 25 \times \tan(\cos^{-1}0.6) = 25 \times 1.3333 = 33.33\ \text{kVAR} \end{aligned}$$

No load: current is 25% of full-load current, pf 0.1

$$\begin{aligned} S_{FL} &= \frac{38.89}{0.9} = 43.21\ \text{kVA}, \quad S_{NL} = 0.25 \times 43.21 = 10.80\ \text{kVA} \\ P_{NL} &= 10.80 \times 0.1 = 1.080\ \text{kW}, \quad Q_{NL} = 10.80 \times \sin(\cos^{-1}0.1) = 10.75\ \text{kVAR} \end{aligned}$$

Capacitor rating (line pf 0.8 at half load)

$$\begin{aligned} Q_C &= P_{HL}(\tan\phi_1 - \tan\phi_2) = 25(1.3333 - 0.75) = 14.58\ \text{kVAR} \end{aligned}$$

(i) Line pf at full load

$$\begin{aligned} Q' &= 18.83 - 14.58 = 4.25\ \text{kVAR (lagging)} \\ \cos\phi &= \frac{38.89}{\sqrt{38.89^2 + 4.25^2}} = 0.994\ \text{lagging} \end{aligned}$$

(ii) Line pf at no load

$$\begin{aligned} Q' &= 10.75 - 14.58 = -3.84\ \text{kVAR (leading)} \\ \cos\phi &= \frac{1.080}{\sqrt{1.080^2 + 3.84^2}} = 0.271\ \text{leading} \end{aligned}$$

Answer: Capacitor $= 14.58$ kVAR; line pf (i) full load $\approx 0.994$ lagging, (ii) no load $\approx 0.271$ leading.

Demand-side management (DSM) is the set of utility-sponsored programmes and consumer actions that change the level and timing of electricity demand (the load shape) so that the power system can be operated more economically and reliably, instead of only adding supply.

Significance in modern power systems

1. Reduces peak demand: defers or avoids costly peaking plants, transmission and distribution upgrades.
2. Improves load factor: flatter load curve gives better use of existing generation, especially run-of-river hydro.
3. Lowers cost: cheaper supply for utilities and lower bills for consumers.
4. Reliability: reduces overloading and helps avoid load shedding and blackouts.
5. Integration of renewables: flexible demand follows variable solar and wind output.
6. Environmental benefit: less fossil generation and fewer emissions.
7. Reduced losses: lower peak current and better pf cut $I^2R$ losses.
8. Enabled by smart grid: smart meters, communication and automation make DSM practical.

DSM techniques

A. Load-shape objectives

 Load                    Load
  |    /\    peak         |    __      after DSM
  |   /  \   clipped -->  |  _/  \__   (flatter)
  |__/    \__             | /      \
  +---------- time        +---------- time

B. Means of implementation

1. Energy efficiency: efficient appliances, lighting, motors with VFDs, building insulation, energy audits.
2. Pricing/tariff methods: time-of-day and seasonal tariffs, kVA demand charges, critical-peak and real-time pricing.
3. Demand response: consumers reduce or shift load on utility signal or price; direct load control.
4. Smart metering and automation: AMI, home energy management systems.
5. Storage: battery and thermal storage to shift energy.
6. Power factor correction and voltage optimisation.
7. Awareness and incentives: rebates, labelling, education.

Together these optimise energy consumption by using cheaper off-peak energy, reducing waste and keeping the system within capacity.

The supply voltage is not stated; since the capacitors are rated 3300 V, the motor is taken as a 3300 V, 3-phase motor and the 6 capacitors in each delta limb are taken as connected in parallel (each sees the full 3300 V line voltage).

Motor input

$$P = \frac{\text{output}}{\eta} = \frac{340}{0.85} = 400\ \text{kW}$$

i) kVAR rating of the capacitor bank

$$\begin{aligned} \tan\phi_1 &= \tan(\cos^{-1}0.8) = 0.75, \quad \tan\phi_2 = \tan(\cos^{-1}0.96) = 0.2917 \\ Q_C &= P(\tan\phi_1 - \tan\phi_2) = 400(0.75 - 0.2917) = 183.33\ \text{kVAR} \end{aligned}$$

ii) Capacitance of each limb (delta connected)

kVAR per limb $= 183.33/3 = 61.11$ kVAR; voltage across each limb $= V_L = 3300$ V.

$$\begin{aligned} C_{limb} &= \frac{Q_{limb}}{\omega V^2} = \frac{61\,111}{2\pi \times 50 \times 3300^2} \\ &= 17.86 \times 10^{-6}\ \text{F} = 17.86\ \mu\text{F} \end{aligned}$$

iii) Capacitance of each capacitor

Each limb has 6 equal 3300 V capacitors in parallel:

$$C = \frac{17.86}{6} = 2.98\ \mu\text{F}$$

        L1
        /\
   C=17.86 uF   each limb = 6 x 2.98 uF
      /    \     in parallel, 3300 V
   L2 ------ L3

Answer: (i) 183.33 kVAR, (ii) 17.86 μF per limb, (iii) 2.98 μF per capacitor.

Power factor is the cosine of the angle between voltage and current, $\cos\phi = P/S$. A low (lagging) power factor means the load draws large reactive current for the same useful power.

Causes of low power factor

1. Induction motors, especially when lightly loaded (pf about 0.2–0.3 at no load, 0.8–0.9 at full load); they are the largest industrial load.
2. Transformers working at light load, drawing magnetising current.
3. Arc and induction furnaces and welding sets, which have high reactance.
4. Discharge lamps (fluorescent, mercury, sodium) with chokes.
5. Supply voltage above rated, which increases magnetising current.
6. Power electronic loads (rectifiers, drives) with phase-controlled firing.

Disadvantages of low power factor

For the same power, current $I = P/(\sqrt3 V \cos\phi)$ increases, so:

1. Larger kVA rating of generators, transformers and switchgear is needed (higher capital cost).
2. Larger conductor size is needed for the same loss.
3. Higher copper losses ($I^2R$), so lower efficiency.
4. Higher voltage drop, poor voltage regulation.
5. Reduced handling capacity of the system.
6. Consumers pay more under kVA-demand tariffs or pf penalties.

Methods of power factor improvement

1. Static capacitors: connected in parallel (star or delta) with the load, supply leading kVAR. Low loss, little maintenance, no moving parts; used individually on motors or as automatic capacitor banks.
2. Synchronous condenser: an over-excited synchronous motor on no load acts as a variable capacitor; gives stepless control, used in large substations.
3. Phase advancer: an ac exciter on the rotor of an induction motor supplies magnetising ampere-turns at slip frequency, so the motor can run at unity or leading pf.
4. Static VAR compensator / STATCOM: thyristor or IGBT controlled devices for fast, continuous control.
5. Good practice: avoid running motors and transformers on light load, use correct motor size, use synchronous motors where possible.

  Supply ---+---------+-----> to load
            |         |
           === C    [Load]
            |       (lagging)
  --------- +---------+
  capacitor supplies leading kVAR

Given: $S = 1200$ kVA at pf 0.75 lag, 3000 h/year, tariff Rs 5000/kVA of maximum demand per year + Rs 5/kWh; pf corrector cost Rs 8000/kVAR, annual interest and depreciation 10%.

i) Annual charge at pf 0.75

$$\begin{aligned} P &= 1200 \times 0.75 = 900\ \text{kW} \\ \text{MD charge} &= 1200 \times 5000 = \text{Rs } 6\,000\,000 \\ \text{Energy} &= 900 \times 3000 = 2\,700\,000\ \text{kWh} \\ \text{Energy charge} &= 2\,700\,000 \times 5 = \text{Rs } 13\,500\,000 \\ \text{Annual charge} &= \text{Rs } 19\,500\,000 \end{aligned}$$

ii) After raising pf to 0.95

kVAR required:

$$\begin{aligned} Q_C &= P(\tan\phi_1 - \tan\phi_2) = 900(0.8819 - 0.3287) = 497.9\ \text{kVAR} \end{aligned}$$

New maximum demand:

$$S_2 = \frac{900}{0.95} = 947.37\ \text{kVA}$$

Annual charges:

$$\begin{aligned} \text{MD charge} &= 947.37 \times 5000 = \text{Rs } 4\,736\,842 \\ \text{Energy charge} &= \text{Rs } 13\,500\,000 \ (\text{unchanged}) \\ \text{Capital cost} &= 497.9 \times 8000 = \text{Rs } 3\,983\,278 \\ \text{Interest + depreciation} &= 0.10 \times 3\,983\,278 = \text{Rs } 398\,328 \\ \text{Total} &= 4\,736\,842 + 13\,500\,000 + 398\,328 = \text{Rs } 18\,635\,170 \end{aligned}$$

Answer: (i) Rs 19,500,000 per year; (ii) 497.9 kVAR needed, new annual charge Rs 18,635,170, an annual saving of about Rs 864,830.

Different consumer classes are given different tariff structures because the cost of supplying each class is different, and because the utility uses tariffs to shape demand and meet social goals.

1. Different cost of service: consumers at high voltage (33/66/132 kV) need no distribution transformers or LV lines and cause fewer losses, so their cost per kWh is lower than for LV domestic consumers.
2. Different load pattern: load factor, diversity factor and time of maximum demand differ. Industries with high load factor use plant better; domestic loads peak in the evening and add to system peak.
3. Size of demand: large consumers need dedicated feeders, and their demand (kVA) is billed separately using a two-part tariff; small consumers get simple flat or block tariffs.
4. Power factor: industrial inductive loads draw reactive power, so they are billed on kVA or penalised for low pf.
5. Metering and billing cost: simple energy meters for small consumers, ToD/demand meters for large ones.
6. Social and economic policy: lifeline (low) rates for poor domestic users, lower rates for irrigation and drinking water, support for cottage industries, encouragement of EV charging.
7. Demand-side management: ToD and seasonal tariffs for industry and commercial users encourage shifting load to off-peak hours.

Example (NEA): domestic consumers pay block (slab) energy charges by ampere rating, while large industries pay a monthly demand charge per kVA plus time-of-day energy charges.

Nepal's power system is mostly run-of-river hydropower with little storage, so DSM is very important for matching demand with this kind of supply.

1. Reducing the evening peak: demand peaks in the evening (about 17:00–23:00) when lighting and cooking coincide. DSM (ToD tariff, efficient lighting) cuts this peak and reduces the need for imports from India or for costly peaking plants.
2. Using wet-season surplus: in the monsoon there is surplus energy and spill at night. Valley filling and strategic load growth (electric cooking, EV charging, industries at night) use this energy instead of wasting it.
3. Dry-season deficit: in winter, generation falls and Nepal imports power. Conservation and load shifting reduce imports and save foreign currency.
4. Avoiding load shedding: Nepal faced long load shedding until 2018; demand management together with better supply helps prevent it from returning.
5. Reducing losses: high technical losses in distribution are reduced by lower peaks and pf correction.
6. Lower cost for consumers and NEA: deferring new lines and substations reduces investment needs.
7. Replacing imported fuels: shifting cooking and transport from LPG and petroleum to electricity improves energy security and trade balance.
8. Environment: less diesel and fossil use; supports clean-energy goals.

Examples in Nepal: NEA's time-of-day tariff for industries, CFL/LED lamp distribution programmes, seasonal tariff differences, and promotion of induction cooking and electric vehicles.

Given: energy 50,000 kWh/year, pf 0.7 lag, maximum demand 400 kVA, tariff Rs 120/kVA + Rs 5.50/kWh, corrector Rs 1000/kVAR, annual charges 10%, pf raised to 0.9. The demand charge is taken per kVA per year, as printed.

Annual cost of supply at pf 0.7

$$\begin{aligned} \text{MD charge} &= 400 \times 120 = \text{Rs } 48\,000 \\ \text{Energy charge} &= 50\,000 \times 5.50 = \text{Rs } 275\,000 \\ \text{Annual cost} &= \text{Rs } 323\,000 \end{aligned}$$

Corrector rating

Maximum-demand kW $= 400 \times 0.7 = 280$ kW.

$$\begin{aligned} Q_C &= 280(\tan\phi_1 - \tan\phi_2) = 280(1.0202 - 0.4843) = 150.05\ \text{kVAR} \\ \text{Cost} &= 150.05 \times 1000 = \text{Rs } 150\,047 \\ \text{Annual charge} &= 0.10 \times 150\,047 = \text{Rs } 15\,005 \end{aligned}$$

New demand and saving

$$\begin{aligned} S_2 &= \frac{280}{0.9} = 311.11\ \text{kVA} \\ \text{Reduction in MD charge} &= (400 - 311.11) \times 120 = \text{Rs } 10\,667 \\ \text{Net annual saving} &= 10\,667 - 15\,005 = -\text{Rs } 4\,338 \end{aligned}$$

The energy charge (kWh) does not change. With the demand charge per year, the device costs more than it saves (net loss of Rs 4,338), so it is not economical.

If the demand charge is Rs 120/kVA per month

This is the usual way demand is billed (e.g. NEA bills demand monthly):

$$\begin{aligned} \text{Annual cost} &= 400 \times 120 \times 12 + 275\,000 = \text{Rs } 851\,000 \\ \text{MD saving} &= 88.89 \times 1440 = \text{Rs } 128\,000 \\ \text{Net saving} &= 128\,000 - 15\,005 = \text{Rs } 112\,995 \end{aligned}$$

Answer: Annual cost Rs 323,000; corrector 150.05 kVAR costing Rs 150,047. On a yearly demand charge the net saving is −Rs 4,338 (a loss). On a monthly demand charge the annual cost is Rs 851,000 and the net saving is about Rs 112,995 per year.

Role of load management in DSM

Load management is the part of DSM that controls the time and level of demand (rather than total energy) so that the load curve becomes flatter.

• Peak clipping: reduces load at system peak through direct load control or interruptible supply.
• Valley filling: adds load during off-peak periods (night pumping, EV charging).
• Load shifting: moves flexible loads from peak to off-peak time.
• It improves load factor, reduces peak generation and network capacity needs, avoids load shedding, and lowers the cost of supply. Tools are tariffs, ripple/remote control of loads, timers, storage and smart meters.

 Demand
   |       /\  peak       --> clipped / shifted
   |   ___/  \___
   |  /          \__  valley --> filled
   +------------------ time

Tariff as a part of DSM

A tariff is the rate schedule by which a utility charges consumers. Besides recovering costs, a tariff sends price signals that change consumer behaviour:

• Time-of-day (ToD) tariff: high rate at peak, low at off-peak, so consumers shift loads.
• Seasonal tariff: different rates for wet and dry seasons to match hydro availability.
• Demand (kVA) charge: charges maximum demand, so consumers limit peaks and improve pf.
• Power factor penalty/incentive: encourages capacitors.
• Interruptible tariff: lower rate for consumers who accept curtailment.
• Block (slab) tariff: increasing rates for higher use encourage conservation.

Types of tariff implemented in Nepal (NEA)

As per the NEA tariff schedule (rates revised by the Electricity Regulatory Commission from time to time):

1. Domestic: by ampere rating (5, 15, 30, 60 A and 3-phase); a monthly minimum/service charge plus block (slab) energy charges that increase with consumption; a low lifeline rate for small users.
2. Two-part tariff: for industrial, commercial and other larger consumers: demand charge (Rs/kVA/month) + energy charge (Rs/kWh), different for LV, MV (11/33 kV) and HV (66/132 kV) supply.
3. Time-of-day (ToD) tariff: for MV/HV industries and other bulk consumers: peak (about 17:00–23:00), normal (05:00–17:00) and off-peak (23:00–05:00) energy rates, with seasonal (wet/dry) variation.
4. Category tariffs: separate rates for industrial, commercial, non-commercial, irrigation, drinking water, transport/EV charging, street lights, temples and community (bulk) consumers.
5. Power factor provision: consumers billed on kVA demand, with penalty for pf below the specified limit.
6. Bulk supply tariff: for community electricity user groups, who distribute locally.

Demand response (DR) is a programme in which consumers reduce or shift their electricity use for a period in response to a price signal or a request from the utility, usually at times of peak demand or system stress, and receive lower bills or incentive payments in return.

Types of DR programmes

• Price-based: time-of-use, critical-peak pricing, real-time pricing.
• Incentive-based: direct load control (utility switches ACs, water heaters, pumps), interruptible/curtailable contracts, demand bidding.

 Utility --(price/signal)--> Smart meter --> Consumer
    ^                                          |
    |      reduced/shifted load at peak        |
    +------------------------------------------+

Benefits for consumers

1. Lower bills: using energy at cheaper off-peak rates and earning incentive payments.
2. Control and awareness: smart meters and apps show usage, helping consumers use energy wisely.
3. Better reliability: fewer blackouts and load shedding events.
4. Lower long-term tariffs: utility saves on peaking plants and network expansion, which keeps future tariffs down.
5. Environmental benefit: less use of polluting peaking plants.

Benefits for utility companies

1. Peak reduction: avoids or defers new generation, transmission and distribution capacity.
2. Lower cost of supply: avoids expensive peak purchases and imports; reduces market price spikes.
3. Better asset use: improved load factor and reduced losses.
4. System reliability and security: DR acts as a fast reserve that can be called during contingencies.
5. Renewable integration: demand follows variable solar/wind or hydro output.

How DR helps avoid blackouts

• When generation is short or a line or plant trips, demand above capacity would cause frequency to fall and lead to load shedding or a cascading blackout.
• DR quickly reduces non-essential load (by thousands of consumers at once), restoring balance between supply and demand, so the operator does not need to cut whole feeders.
• It relieves overloaded transformers and lines during peak, preventing equipment failure.

How DR reduces electricity costs

• The most expensive generation (diesel or imported power) runs only at peak; reducing peak demand avoids this cost.
• Lower capital investment in plants used only a few hours per year.
• Consumers who shift load to off-peak pay lower rates and receive incentives.

Example: in Nepal, a ToD tariff that charges industries more at 17:00–23:00 encourages them to run heavy loads at night, reducing evening peak and import of costly power.

Given: $S = 1200$ kVA, pf 0.75 lag, 3000 h/year; tariff Rs 1300/kVA of maximum demand per year + 80 paisa (Rs 0.80)/kWh; corrector Rs 1200/kVAR; interest and depreciation 10%.

i) Annual charge at pf 0.75

$$\begin{aligned} P &= 1200 \times 0.75 = 900\ \text{kW} \\ \text{MD charge} &= 1200 \times 1300 = \text{Rs } 1\,560\,000 \\ \text{Energy charge} &= 900 \times 3000 \times 0.80 = \text{Rs } 2\,160\,000 \\ \text{Annual charge} &= \text{Rs } 3\,720\,000 \end{aligned}$$

ii) kVAR required for pf 0.95

$$\begin{aligned} \tan\phi_1 &= \tan(\cos^{-1}0.75) = 0.8819, \quad \tan\phi_2 = \tan(\cos^{-1}0.95) = 0.3287 \\ Q_C &= 900(0.8819 - 0.3287) = 497.9\ \text{kVAR} \end{aligned}$$

New annual charge

$$\begin{aligned} S_2 &= \frac{900}{0.95} = 947.37\ \text{kVA} \\ \text{MD charge} &= 947.37 \times 1300 = \text{Rs } 1\,231\,579 \\ \text{Energy charge} &= \text{Rs } 2\,160\,000 \\ \text{Corrector cost} &= 497.9 \times 1200 = \text{Rs } 597\,492 \\ \text{Interest + depreciation} &= 0.10 \times 597\,492 = \text{Rs } 59\,749 \\ \text{New annual charge} &= 1\,231\,579 + 2\,160\,000 + 59\,749 = \text{Rs } 3\,451\,328 \end{aligned}$$

Answer: (i) Rs 3,720,000 per year; (ii) 497.9 kVAR, new annual charge Rs 3,451,328 (saving about Rs 268,672 per year).

Tariff

A tariff is the schedule of rates and the method by which an electric utility charges consumers for the electrical energy and the demand they use. It should recover the cost of generation, transmission and distribution, give a fair return, and be simple and fair to consumers.

Types of tariff used in industrial billing by NEA

As per NEA's tariff schedule (rates are revised by the Electricity Regulatory Commission from time to time):

1. Two-part tariff: a demand charge per kVA of contracted/maximum demand per month plus an energy charge per kWh used. Billing demand in kVA also makes low-pf consumers pay more.
2. Voltage-level based rates: separate demand and energy rates for LV (230/400 V: rural, cottage and small industries), MV (11 kV and 33 kV: medium industries) and HV (66 kV and above: large industries). Higher supply voltage gets lower rates.
3. Time-of-day (ToD) tariff: compulsory for MV/HV industrial consumers with ToD meters. Energy rates differ for peak (about 17:00–23:00), normal (05:00–17:00) and off-peak (23:00–05:00) periods.
4. Seasonal tariff: ToD rates differ between the wet season (Baisakh–Mangsir) and the dry season (Poush–Chaitra) to match hydro availability.
5. Power factor provisions and minimum charge: penalty for pf below the set limit and a minimum monthly charge on contracted demand.

Demand side management techniques for controlling peak demand aim to reduce or move the load that occurs at the system peak (evening hours in Nepal).

 Load  peak clipping  load shifting  valley filling
  |      ___            ___ -->         ___
  |     /cut\          /   \  later    /   \  +fill
  |____/     \___   __/     \___    __/     \__/
  +--------------- time

1. Peak clipping: direct reduction of load at peak by the utility, e.g. remote switching off of water heaters, pumps or air conditioners (direct load control), or interruptible supply for large consumers.
2. Load shifting: moving flexible loads from peak to off-peak hours, e.g. industries running arc furnaces, crushers or pumps at night; water pumping and EV charging at night.
3. Valley filling: encouraging new loads in off-peak periods so that the load curve is flatter and peak share falls.
4. Time-of-day (ToD) and critical-peak pricing: higher rates at peak make consumers reduce peak use voluntarily.
5. Demand response programmes: consumers reduce load on utility signal in return for incentives.
6. Energy storage: batteries or thermal storage charge off-peak and supply at peak.
7. Energy-efficient appliances: LED lighting and efficient motors reduce evening peak, which in Nepal is mostly lighting and cooking.
8. Maximum demand control: demand controllers or load limiters at the consumer end trip non-essential loads when demand approaches a set limit.

Factors affecting the tariff

A tariff must recover the full cost of supplying energy and give a fair return. The main factors considered are:

1. Fixed (capital) cost: interest and depreciation on generation, transmission and distribution plant; this depends on the maximum demand.
2. Running cost: fuel, wages, maintenance; this depends on the energy (kWh) supplied.
3. Load factor and diversity factor of the consumer: a high load factor uses the plant better, so it deserves a lower rate.
4. Power factor: low pf needs larger plant (more kVA), so it is penalised.
5. Time of use: supply at peak hours costs more than at off-peak hours.
6. Type and size of consumer (domestic, commercial, industrial, irrigation) and supply voltage (LV, MV, HV).
7. Quantity of energy used, profit margin, taxes, and social or government policy (subsidies, lifeline block).

Two-part tariff

The total bill is split into two parts:

$$\text{Bill} = a \times \text{kW (or kVA) of max. demand} + b \times \text{kWh}$$

• The first part (demand charge) recovers the fixed cost; the second part (energy charge) recovers the running cost.
• Used for industrial and large commercial consumers.
• Merit: fair, since each consumer pays for the plant capacity he reserves. Demerit: needs a maximum demand meter, and the consumer pays the fixed part even if little energy is used.

Time of day (TOD) tariff

The energy rate differs with the time at which energy is used.

• The day is divided into peak, normal and off-peak periods; the peak rate is highest and the off-peak rate lowest. In Nepal, NEA's TOD tariff for industries uses peak (about 17:00–23:00), off-peak (about 23:00–05:00) and normal (05:00–17:00) periods.
• It encourages consumers to shift loads (pumping, furnaces, charging) to off-peak hours, which flattens the load curve and improves the utility's load factor.
• It needs a TOD (multi-register) energy meter.

Demand side management (DSM) in Nepal is carried out mainly by Nepal Electricity Authority (NEA) together with the Ministry of Energy, Water Resources and Irrigation, AEPC and donor programmes. Effective techniques used are:

1. Efficient lighting programme: NEA distributed CFL lamps (around 2010–11) and later promoted LED lamps in place of incandescent bulbs. This cut the evening peak load by several tens of MW.
2. Time of day (TOD) tariff: industries and bulk consumers are billed at higher rates in the evening peak (about 17:00–23:00) and lower rates at night, so load is shifted to off-peak hours.
3. Power factor penalty: industrial consumers with low pf (below about 0.8–0.85) pay extra, which encourages capacitor installation and reduces kVA demand.
4. Load building in off-peak/surplus periods: after load shedding ended (2018), the government promoted electric (induction) cooking, electric vehicles (lower customs duty and tax) and electric heating to use surplus energy, especially in the wet season and at night.
5. Dedicated and trunk-line feeders for industries, with separate tariffs, and control of large loads during peak hours.
6. Energy efficiency programmes: Nepal Energy Efficiency Programme (NEEP, with GIZ), energy audits of industries, and awareness campaigns on efficient appliances.
7. Distributed and renewable sources: solar water heaters, rooftop solar with net metering (net metering guideline of NEA), which reduce grid demand during the day.
8. Reduction of losses: smart and prepaid meters, anti-theft drives and network upgrading, which reduce wasted energy and peak demand.

Compare the annual cost of each motor: demand charge + energy charge + interest and depreciation on the extra capital. The tariff of Rs 250 per kVA of maximum demand is taken as an annual charge, and "the motor costs Rs 1500 less" is read as motor B costs Rs 1500 less than motor A.

Motor A ($\eta$ = 85%, pf = 0.9)

$$\begin{aligned} P_{in,A} &= \frac{35}{0.85} = 41.18\ \text{kW} \\ S_A &= \frac{41.18}{0.9} = 45.75\ \text{kVA} \\ \text{Demand charge} &= 250 \times 45.75 = \text{Rs } 11{,}438 \\ \text{Energy charge} &= 8 \times 41.18 \times 3000 = \text{Rs } 988{,}235 \\ \text{Extra capital cost charge} &= 0.10 \times 1500 = \text{Rs } 150 \end{aligned}$$

Annual cost of A = 11,438 + 988,235 + 150 = Rs 999,823

Motor B ($\eta$ = 90%, pf raised from 0.8 to 0.85)

$$\begin{aligned} P_{in,B} &= \frac{35}{0.9} = 38.89\ \text{kW} \\ \tan\phi_1 &= \tan(\cos^{-1}0.8) = 0.75,\quad \tan\phi_2 = \tan(\cos^{-1}0.85) = 0.6197 \\ Q_C &= 38.89\,(0.75 - 0.6197) = 5.07\ \text{kVAR} \\ \text{Cost of condenser} &= 400 \times 5.07 = \text{Rs } 2026 \\ \text{Interest and depreciation} &= 0.10 \times 2026 = \text{Rs } 202.6 \\ S_B &= \frac{38.89}{0.85} = 45.75\ \text{kVA} \\ \text{Demand charge} &= 250 \times 45.75 = \text{Rs } 11{,}438 \\ \text{Energy charge} &= 8 \times 38.89 \times 3000 = \text{Rs } 933{,}333 \end{aligned}$$

Annual cost of B = 11,438 + 933,333 + 202.6 = Rs 944,974

Comparison

Both motors draw the same kVA, so the higher efficiency of B decides the result.

Answer: Motor B (with condensers) is more economical, saving about Rs 54,849 per year.

Data: working hours = 16 × 300 = 4800 h/year; average load 250 kW; maximum demand 300 kW at 0.8 pf.

$$\begin{aligned} \text{Energy used} &= 250 \times 4800 = 1{,}200{,}000\ \text{kWh} \\ \text{Max demand} &= \frac{300}{0.8} = 375\ \text{kVA} \end{aligned}$$

Low voltage supply

$$\begin{aligned} \text{Demand charge} &= 60 \times 12 \times 375 = \text{Rs } 270{,}000 \\ \text{Energy charge} &= 1.1 \times 1{,}200{,}000 = \text{Rs } 1{,}320{,}000 \\ \text{Total} &= \text{Rs } 1{,}590{,}000 \end{aligned}$$

High voltage supply

With HV supply the consumer owns the transformer and switchgear, and their 5% losses are metered on the HV side. The HV equipment is rated for the factory's 375 kVA maximum demand.

$$\begin{aligned} \text{Max demand on HV side} &= \frac{375}{0.95} = 394.74\ \text{kVA} \\ \text{Energy on HV side} &= \frac{1{,}200{,}000}{0.95} = 1{,}263{,}158\ \text{kWh} \\ \text{Demand charge} &= 50 \times 12 \times 394.74 = \text{Rs } 236{,}842 \\ \text{Energy charge} &= 1 \times 1{,}263{,}158 = \text{Rs } 1{,}263{,}158 \\ \text{Cost of HV equipment} &= 500 \times 375 = \text{Rs } 187{,}500 \\ \text{Interest and depreciation} &= 0.12 \times 187{,}500 = \text{Rs } 22{,}500 \\ \text{Total} &= 236{,}842 + 1{,}263{,}158 + 22{,}500 = \text{Rs } 1{,}522{,}500 \end{aligned}$$

Answer: Difference in annual cost = Rs 67,500; the high voltage supply is cheaper.

(If the HV equipment is instead rated for 394.74 kVA, its annual charge is Rs 23,684 and the difference becomes Rs 66,316.)

Demand side management (DSM) is the planning and implementation of utility activities that influence the customer's use of electricity so as to produce desired changes in the utility's load shape (time pattern and amount of demand).

Benefits of DSM

To the utility

• Reduces peak demand, so new generation, transmission and distribution capacity can be postponed.
• Improves load factor and plant utilisation; lowers cost per kWh.
• Reduces the need for costly peaking plants and imports during peak hours.
• Improves system reliability and voltage profile; reduces load shedding.
• Reduces losses in the network.

To the consumer

• Lower electricity bills (efficient appliances, off-peak tariffs).
• Better quality and reliability of supply.
• Incentives and rebates from utility programmes.

To society and environment

• Saves energy resources and capital for the nation.
• Reduces emission of greenhouse gases and pollution.
• Creates jobs in energy services and efficient-equipment markets.

Energy efficiency vs DSM

Energy efficiency means using less energy to give the same service (light, heat, motion), e.g. replacing an incandescent lamp with an LED lamp. It is one tool inside DSM.

So all energy efficiency measures are a part of DSM, but DSM also includes measures that only move load in time without saving energy.

Data: working hours = 2 × 8 × 285 = 4560 h/year; average load 250 kW; maximum demand 300 kW at 0.8 pf.

$$\begin{aligned} \text{Energy used} &= 250 \times 4560 = 1{,}140{,}000\ \text{kWh} \\ \text{Max demand} &= \frac{300}{0.8} = 375\ \text{kVA} \end{aligned}$$

Low voltage supply

$$\begin{aligned} \text{Demand charge} &= 650 \times 12 \times 375 = \text{Rs } 2{,}925{,}000 \\ \text{Energy charge} &= 13 \times 1{,}140{,}000 = \text{Rs } 14{,}820{,}000 \\ \text{Total} &= \text{Rs } 17{,}745{,}000 \end{aligned}$$

Medium voltage supply

The consumer installs the transformer and switchgear (rated for the 375 kVA demand); their 5% losses are metered on the MV side.

$$\begin{aligned} \text{Max demand on MV side} &= \frac{375}{0.95} = 394.74\ \text{kVA} \\ \text{Energy on MV side} &= \frac{1{,}140{,}000}{0.95} = 1{,}200{,}000\ \text{kWh} \\ \text{Demand charge} &= 1300 \times 12 \times 394.74 = \text{Rs } 6{,}157{,}895 \\ \text{Energy charge} &= 12 \times 1{,}200{,}000 = \text{Rs } 14{,}400{,}000 \\ \text{Equipment cost} &= 700 \times 375 = \text{Rs } 262{,}500 \\ \text{Interest and depreciation} &= 0.10 \times 262{,}500 = \text{Rs } 26{,}250 \\ \text{Total} &= \text{Rs } 20{,}584{,}145 \end{aligned}$$

The MV demand charge (Rs 1300/kVA/month) is double the LV one, so it outweighs the Re 1/unit lower energy rate.

Answer: Difference in annual cost = Rs 2,839,145 (about Rs 28.4 lakh); the low voltage supply is cheaper.

Demand side management (DSM) is the set of utility activities designed to influence the amount and timing of customers' electricity use so that the utility's load shape changes in a desired way. Instead of building more supply to meet demand (supply side), DSM manages the demand itself.

Concept: load shape objectives

 Utility load curve (kW vs time of day)
        peak
 kW     /\         clip the peak
 |   __/  \__      fill the valley
 |__/        \__   shift peak -> night
 |  valley       
 +------------------ time

1. Peak clipping: reduce load at peak hours (direct load control).
2. Valley filling: build load in off-peak hours (night pumping, EV charging).
3. Load shifting: move load from peak to off-peak (TOD tariff, storage heaters).
4. Strategic conservation: reduce energy use overall (efficient lamps, motors).
5. Strategic load growth: increase sales in a planned way (electric cooking).
6. Flexible load shape: interruptible loads that can be curtailed when needed, for a lower tariff.

Steps in DSM planning and implementation

1. Set objectives: define the utility's goals (reduce peak, defer new plant, cut losses, improve load factor).
2. Load research and data collection: study the load curve, consumer categories and end uses; identify where and when demand is high.
3. Identify DSM alternatives: list possible technologies and programmes (efficient lighting, pf correction, TOD tariff, load control, solar water heaters).
4. Evaluate alternatives: cost–benefit analysis from the view of utility, participant and society (tests such as total resource cost, ratepayer impact); estimate MW and MWh savings.
5. Select programmes that are cost-effective and acceptable to customers.
6. Design the programme: target customers, incentives, tariffs, delivery mechanism, marketing.
7. Implementation: pilot programme, customer awareness, training, procurement and installation.
8. Monitoring and evaluation: measure actual savings and load shape change; give feedback to improve the programme.

DSM planning is continuous; results of monitoring feed back into the next planning cycle and into the utility's integrated resource plan.

(i) Present annual charge

$$\begin{aligned} P &= 1200 \times 0.75 = 900\ \text{kW} \\ \text{Demand charge} &= 65 \times 1200 = \text{Rs } 78{,}000 \\ \text{Energy charge} &= 0.02 \times 900 \times 3000 = \text{Rs } 54{,}000 \\ \text{Annual charge} &= \text{Rs } 132{,}000 \end{aligned}$$

(ii) After improving pf to 0.95

The capacitor rating is found from the load kW (the small apparatus loss is treated as an added energy cost only).

$$\begin{aligned} \tan\phi_1 &= \tan(\cos^{-1}0.75) = 0.8819,\quad \tan\phi_2 = \tan(\cos^{-1}0.95) = 0.3287 \\ Q_C &= 900\,(0.8819 - 0.3287) = 497.9\ \text{kVAR} \\ \text{New max demand} &= \frac{900}{0.95} = 947.37\ \text{kVA} \\ \text{Demand charge} &= 65 \times 947.37 = \text{Rs } 61{,}579 \\ \text{Apparatus loss} &= 0.05 \times 497.9 = 24.9\ \text{kW} \\ \text{Energy charge} &= 0.02 \times (900 + 24.9) \times 3000 = \text{Rs } 55{,}494 \\ \text{Capital cost} &= 60 \times 497.9 = \text{Rs } 29{,}875 \\ \text{Interest and depreciation} &= 0.10 \times 29{,}875 = \text{Rs } 2{,}987 \\ \text{New annual charge} &= 61{,}579 + 55{,}494 + 2{,}987 = \text{Rs } 120{,}060 \end{aligned}$$

Answer: (i) Rs 132,000 per year; (ii) kVAR required = 497.9 kVAR, new annual charge = Rs 120,060 (saving about Rs 11,940 per year).

Tariff is the rate (schedule of charges) at which electrical energy is sold to a consumer. It must recover the fixed cost, the running cost and a reasonable profit, and should be simple, fair and encourage good use of the plant.

1. Simple (flat rate per unit) tariff

Fixed rate per kWh, e.g. Rs 10/kWh, for all units.

• Merits: simple to understand and bill.
• Demerits: does not separate fixed and running cost; small and large consumers pay the same rate; no incentive for high load factor.

2. Flat rate tariff

Different per-unit rates for different types of consumers (lighting, power).

• Merits: fairer than simple tariff between consumer classes.
• Demerits: separate meters and wiring for each class; rate is fixed for a class whatever the consumption.

3. Block rate tariff

Energy is divided into blocks with a different rate for each block (rate falls for later blocks, or rises, as in Nepal's domestic tariff).

• Merits: large consumers get a lower average rate (declining block); a rising block (as in NEA) protects poor users and discourages waste.
• Demerits: no account of maximum demand or time of use.

4. Two-part tariff

Bill = a × kW (or kVA) maximum demand + b × kWh.

• Merits: fixed cost recovered from demand charge, running cost from energy; fair; suits industries.
• Demerits: needs maximum demand meter; consumer pays the fixed part even when little energy is used.

5. Maximum demand tariff

Like two-part but maximum demand is actually measured by an MD meter.

• Merits: removes the objection of an assessed demand.
• Demerits: costly metering; suitable only for big consumers.

6. Power factor tariff

Charges depend on pf: kVA maximum demand tariff, sliding scale, or kW and kVAR tariff.

• Merits: penalises low pf, encourages pf correction, reduces plant size.
• Demerits: extra metering; complex.

7. Three-part tariff

Bill = a (fixed per consumer) + b × kW + c × kWh.

• Merits: recovers customer, demand and energy costs separately; most scientific.
• Demerits: complicated for ordinary consumers; used only for big consumers.

8. Time of day (TOD) tariff

Different energy rates for peak, normal and off-peak periods.

• Merits: shifts load to off-peak, improves load factor; a DSM tool.
• Demerits: needs TOD meters; may be inconvenient for consumers.

Load management is the part of DSM that changes the time at which electricity is used (and the size of the peak) rather than the total energy. Its role in DSM is:

• Peak clipping: cut load at system peak by direct load control (remote switching of water heaters, pumps, air conditioners) or interruptible supply contracts.
• Valley filling: build load in off-peak hours (night pumping, EV charging, thermal storage), which improves load factor.
• Load shifting: move load from peak to off-peak using TOD tariffs, thermal or battery storage.
• Flexible load: customers accept curtailment in emergencies in return for lower tariffs.
• Results: lower peak demand, deferred investment in peaking plants and lines, better plant utilisation, lower cost per unit, reduced load shedding.

Tools used: TOD tariffs, demand charges, interruptible tariffs, ripple/radio control, smart meters, and energy storage.

 kW                         kW
 |     /\   peak            |    ____
 |  __/  \__               |___/    \___  flatter
 |_/        \_  -->        |            \_ curve
 +-------------- time      +-------------- time
   before DSM                 after load management

Steps to implement DSM

1. Define objectives: decide what the utility wants (reduce evening peak, defer new plant, reduce losses, improve load factor).
2. Load research: collect and analyse load curves, customer categories and end-use data to find which loads cause the peak.
3. Identify DSM options: list possible measures such as efficient lighting, pf correction, TOD tariff, direct load control, solar water heaters.
4. Cost–benefit evaluation: estimate kW and kWh impact and test cost-effectiveness for utility, participants and society.
5. Select and design programmes: choose target customers, incentives (rebates, tariff discounts), technology and delivery method.
6. Customer awareness and marketing: inform customers of benefits; publicity, training, dealer involvement.
7. Implementation: start with a pilot programme, then expand; arrange metering, equipment supply and installation.
8. Monitoring and evaluation: measure actual savings and load shape change, compare with targets, and revise the programme.

Saving comes from the reduced kVA demand charge; against it are the capacitor loss (extra kWh) and the interest and depreciation on capacitors. The capacitor kVAR is found from the 200 kW load, and the loss of 100 W per kVA of capacitor rating is taken as 0.1 kW per kVAR.

kVA demand before and after

$$\begin{aligned} S_1 &= \frac{200}{0.85} = 235.29\ \text{kVA}, \qquad S_2 = \frac{200}{0.9} = 222.22\ \text{kVA} \\ \text{Reduction} &= 235.29 - 222.22 = 13.07\ \text{kVA} \\ \text{Saving in demand charge} &= 150 \times 13.07 = \text{Rs } 1960.8 \end{aligned}$$

Capacitor rating and its costs

$$\begin{aligned} \tan\phi_1 &= 0.6197,\quad \tan\phi_2 = 0.4843 \\ Q_C &= 200\,(0.6197 - 0.4843) = 27.08\ \text{kVAR} \\ \text{Loss} &= 0.1 \times 27.08 = 2.708\ \text{kW} \\ \text{Cost of loss} &= 2.708 \times 2500 \times 0.05 = \text{Rs } 338.6 \\ \text{Capital cost} &= 420 \times 27.08 = \text{Rs } 11{,}375 \\ \text{Interest and depreciation} &= 0.10 \times 11{,}375 = \text{Rs } 1137.5 \end{aligned}$$

Net annual saving

$$\begin{aligned} \text{Saving} &= 1960.8 - 338.6 - 1137.5 \\ &= \text{Rs } 484.7 \end{aligned}$$

Answer: Annual saving ≈ Rs 485 (with 27.08 kVAR of capacitors).

Capacitors are loss-free, so the energy (kWh) bill does not change; the saving is in the kVA demand charge, minus the annual charges on the capacitors.

Demand before and after

$$\begin{aligned} S_1 &= \frac{800}{0.8} = 1000\ \text{kVA} \\ S_2 &= \frac{800}{0.9} = 888.89\ \text{kVA} \\ \text{Saving in demand charge} &= 100 \times (1000 - 888.89) = \text{Rs } 11{,}111 \end{aligned}$$

Capacitor rating and its annual cost

$$\begin{aligned} \tan\phi_1 &= \tan(\cos^{-1}0.8) = 0.75,\quad \tan\phi_2 = \tan(\cos^{-1}0.9) = 0.4843 \\ Q_C &= 800\,(0.75 - 0.4843) = 212.54\ \text{kVAR} \\ \text{Capital cost} &= 60 \times 212.54 = \text{Rs } 12{,}753 \\ \text{Interest and depreciation} &= 0.10 \times 12{,}753 = \text{Rs } 1275.3 \end{aligned}$$

Net annual saving

$$\text{Saving} = 11{,}111 - 1275.3 = \text{Rs } 9835.9$$

The energy charge (0.20 × 800 × 3000 = Rs 480,000) is the same before and after, so it does not affect the saving.

Answer: Annual saving ≈ Rs 9,836 (capacitors of 212.54 kVAR).

In the expression Rs $(a + b \cdot \text{kW} + c \cdot \text{kWh})$:

• $a$ = fixed cost that does not depend on demand or energy (organisation, site),
• $b$ = cost per kW of maximum demand (interest and depreciation on plant),
• $c$ = cost per kWh generated (fuel, oil, taxation, operating wages).

Energy generated per year

$$\begin{aligned} \text{Max demand} &= 60\ \text{MW} = 60{,}000\ \text{kW} \\ \text{Units per year} &= 60{,}000 \times 0.5 \times 8760 = 262.8 \times 10^{6}\ \text{kWh} \end{aligned}$$

Constant a

$$a = \text{Rs } 5{,}00{,}000 \ \text{(organisation and interest on site cost)}$$

Constant b

$$\begin{aligned} \text{Interest and depreciation} &= 0.10 \times 5 \times 10^{6} = \text{Rs } 5{,}00{,}000 \\ b &= \frac{5{,}00{,}000}{60{,}000} = \text{Rs } 8.33\ \text{per kW} \end{aligned}$$

Constant c

$$c = \frac{9{,}00{,}000}{262.8 \times 10^{6}} = \text{Rs } 0.003425\ \text{per kWh} \ (\approx 0.34\ \text{paisa/kWh})$$

So the annual cost is Rs $(5{,}00{,}000 + 8.33\,\text{kW} + 0.003425\,\text{kWh})$ at 60 MW and 50% load factor, the total annual cost is 5 + 5 + 9 = Rs 19 lakh.

Answer: a = Rs 5,00,000; b = Rs 8.33/kW; c = Rs 0.003425/kWh.