Pages

Thursday, March 28, 2013

CHAPTER 6 TARIFFS





6.1       COSTS


The users of electricity must pay for what they use.  To provide them with electric power, generating stations must be built and maintained, a transmission and distribution network installed, staff paid and, of course, fuel burnt (except in natural-energy plants such as hydroelectric stations).  All of these must be paid for.

The costs of generation and of transmission and distribution are divided broadly into two groups: ‘capital’ and ‘running’.  Capital costs cover the acquisition of land, building of power stations and transmission and distribution networks, buying the prime mover and generating plant and other equipment such as switchgear and transformers, and setting up the administrative organisation to run the system.

Money for capital costs is basically a ‘one-off’ demand, for which finance has to be raised, usually by borrowing.  This means interest payments and repayment of the capital loan over a definite period.

All plant and equipment deteriorates with use and with time, and its value must be regularly scaled down until it is virtually written off except for its scrap value.  A Depreciation Fund is raised, which can be used either to repay the original loan or to replace the worn-out equip­ment.  The build-up of this fund, along with interest payments, represents a continuing annual charge, called ‘Annual Capital Cost’.

Under ‘running’ costs clearly the principal item is fuel.  The amount used is directly proportional to the loading on the station, and it is therefore necessary for each consumer to pay for the energy actually consumed in order to meet the fuel cost.  Other running costs include labour and day-to-day overheads such as lighting, heating, cleaning, cranage and storekeeping, as well as rates and water charges etc. which are in general not dependent on the station loading.

Maintenance and replacements are also a continuing charge both on the generating plant itself and on the distribution system consisting of switchgear, transformers, lines and substations.  These, together with the other overhead charges referred to above, form part of the broad ‘running’ costs.

In order for the whole system to be viable, the customers using the electric power must pay not only for the energy (fuel) which they consume and a share of the other running costs, but they must also pay a contribution towards the total Annual Capital Cost.

Running costs are simple to calculate.  Each consumer is provided with a meter which records the total energy consumed in kWh or MWh during any accounting period and it is paid for at whatever rate is demanded per ‘unit’ (kWh).

To assess the proper contribution towards the Annual Capital Cost, it is assumed that the size of generating plant and distribution system has already been determined by the sum total of all the individual consumers’ expected demands (with an allowance for growth), the unit generally used being kVA.  For example, if one consumer’s expected load demand has been estimated (by him) to be 10 000kVA, then 10 000kVA of generating and distributing plant must be provided for his use; this must be based on the consumer’s expected maximum demand, since that is what the generating plant will, at some time, have to meet.  Each individual consumer will thus have earmarked a certain proportion of the total generating capacity, and this is the proportion of the Annual Capital Cost which he will be expected to pay.

6.2       TARIFFS


The Authority who supplies power to the consumer must therefore devise a tariff which will recoup enough money from all his customers to pay his own costs.  This tariff will in general be in two parts - one part based solely on the energy consumed to meet fuel and other running costs, the second part based on the maximum demand expected at any time from that consumer.  Large consumers usually pay this part based on ‘Maximum Demand kVA’, although some Boards prefer to charge by ‘Maximum Demand kW’; smaller consumers are usually charged on Maximum Demand kW with a penalty for low power factor.  This element of the tariff is designed to meet each consumer’s contribution to the Annual Capital Cost.
















 


 

 




















FIGURE 6.1
TYPICAL MAXIMUM DEMAND kVA METER

In practice maximum demand is not measured at any given instant but is averaged over successive periods of 30 minutes.  A kVAh integrating meter of the eddy-current type (a typical one is shown in Figure 6.1) indicates by a small moving pointer the total kVAh taken over 30 minutes, after which the pointer resets to zero and starts again.  As it moves forward it pushes a free pointer ahead of it but leaves it behind when it resets to zero.  The free pointer stays in that position unless or until the total kVAh taken during any subsequent 30-minute period exceeds that at which the pointer was left; the pointer is then pushed further on to provide a new maximum reading.  When the meter is read, the position of the free pointer indicates the maximum kVAh taken during the worst 30-minute period and so gives the average kVA during that period.  On this is based the ‘maximum demand’ charge.

The actual charges, both for kWh units and for kVA maximum demand, are determined by the Supply Authority and are often negotiated with important consumers.  The following is a greatly simplified example of such a calculation.

Example

Cost of complete 800MW Power Station installation consisting of:
£100 000 000

            Machinery and Buildings
80 000 000

            Installation
20 000 000




Interest on capital (say 10%)
10 000 000
p.a.
Depreciation over 20 years
4 000 000
p.a.


            Annual Capital Cost
£ 14 000 000
p.a.

Output = 800MW or 1 000MVA

            \ Annual Capital Cost =                    = £14 000 per MVA
                                                                        or £14 per kVA

Fuel cost (say)                                                3p per kWh
Other running costs (say)                               1.5p per kWh


 
            Total Running Cost:                                     4.5p per kWh

The minimum tariff (ignoring profit, etc.) would therefore be:

            £14 p.a. per kVA maximum demand and 4.5p per kWh unit.

Thus a factory which uses 8 000 000 units per year and has a maximum demand of 6 000k VA would pay annually on the above tariff:

   8 x 106 x 4.5p = £360 000 fuel charge
            + 6 x 103 x £14 = £   84 000 maximum demand charge


 
                                         £444 000 total

For domestic consumers, whose bills are paid quarterly, the tariff is usually simpler, based on a simple charge per unit (kWh) and a fixed Standing Charge, all payable quarterly.

From the example given above:

Annual Capital Cost                            =  £14.00 per kW p.a.
                                                                        or £3.50 per kW per quarter

            Assume average domestic
            maximum demand is 5kW,
            then average domestic Annual
            Capital Cost contribution
            (Standing Charge)




= £3.50 x 5
= £17.50 per quarter
            And, as before, unit charge
= 4.5p per kWh unit

Area Electricity Boards usually offer special reduced terms where the maximum demand occurs outside the peak period - for example the ‘Economy 7’ tariff.  This is to encourage consumers to go in for ‘off-peak’ consumption, for example for water heating.  During offpeak periods the consumption is separately metered.

6.3          POWER CORRECTION AND TARIFFS


It is shown in the manual ‘Electric Motors’ how low power factor in a motor may be corrected by the use of capacitors. A powerful reason for doing this is to lower the kVA demanded by such motors, and thereby to reduce the maximum demand charge under the tariff.

Since kVA = , and since the kW demand is determined by the process system and cannot be varied, the kVA is at its lowest value when the kvar is zero, in which case the kVA is equal to the kW loading. This situation occurs when the power factor has been corrected to unity.

Such an exact correction is not however necessary, as Figure 6.2 shows:



FIGURE 6.2
MOTOR POWER FACTOR CORRECTION

Vector OP represents the active current and so the kW loading of a motor, and PQ represents the reactive current and so the kvar.  Vector OQ is then the total uncorrected kVA.  If PQ is reduced by power factor correction, the slope of OQ becomes less until, ideally at unity power factor, OQ lies on top of OP, and the kVA is then at its minimum value and equal to the kW.

If, however, the kvar were not made exactly zero, the motor might be slightly under-corrected (PQ’) or over-corrected (PQ”), in which case OQ’ (or OQ”) does not lie exactly over OQ but still has some slope.  This slope, however, is small, and the difference in length between OP and OQ’ (or OQ”) is negligible.  There is, therefore, little .to be gained by achieving exact correction, and indeed, because correcting capacitors are expensive, there is some virtue in aiming at slight under-correction.  A compromise would be reached, and the small extra maximum demand cost remaining due to under-correction would be set against the cost of the extra capacitance needed to achieve full correction.

No comments:

Post a Comment