Electricity was introduced in Egypt in 1893. Generation and distribution were privately owned and operated for about 70 years, until nationalisation took place in 1962. At that stage the private owners had built only 3000 MW, but since then the Ministry of Electricity has added 13,000 MW, thus continuously keeping supply ahead of demand.
The government of Egypt has been committed to reforming the electric power generation, distribution and transmission components to achieve full commercial operation, and to introduce competition to minimise electricity prices. In 1998, the three electricity components were geographically reorganised to form seven vertically integrated electricity companies responsible for generation and distribution. In 2000, these companies were placed under a joint stock company, the Egyptian Electricity Holding Company (EEHC). Until mid-2001, Egyptian utility customers bought electricity on a bundled basis that provided a package of services, including generation, transmission and distribution and a variety of energy management services.
Major restructuring began in July 2001 with the unbundling of the production, transmission and distribution functions to form 14 companies 100% owned by EEHC. Current law permits the sale of up to 49% of the shares in these companies.
EGYPTIAN POWER POOL
Creation of the Egyptian Power Pool (EPP) was deemed essential to the viable operation of the new companies in the restructured electricity industry. The EPP was developed during 2002. Its fundamental characteristic was a cost-based pool designed to link the 14 main electricity companies through formal agreements. Challenging aspects of developing the EPP have included determining the principles governing the mechanisms for revenue adjustment, cash management and tariff equalisation; setting the terms of the purchase and sales agreements; and the basis for allocation of fixed costs and available profit.
Charges among the electricity companies were designed to allow a well-run PSC to earn a profit. The most prominent function will be the single buyer residing within the Egyptian Electricity Transmission Company (EETC). EETC will be the sole organisation to purchase bulk power from generation companies (and other bulk power providers) and to sell it to distribution companies.
The electricity companies are separate organisations linked through formal arrangements. These include a separate agreement between EETC and each generation and distribution company. The existing BOOT and export/import contracts are presently with EEHC. They will be assigned to EETC, or an agency agreement may be established between EEHC and EETC to manage them.
Based on the terms of the agreements, the National Energy Control Centre (NECC) as part of EETC, continues to direct the operation of the generators and the high voltage transmission system to minimise overall costs while maintaining system reliability. Each distribution company will have responsibility for planning its own system, in some cases with assistance from the rural electricity authority. Each distribution company will also be responsible for the load forecast in its own area. EETC will be responsible for forecasting the loads of the UHV and HV customers.
The agreements will provide for costs that vary with power plant output, and for fixed costs, which include all other costs including profit. Due to issues related to tariffs and collections, the power pool uses a charges model to determine fixed charges and cash payment requirements among the electricity companies. Fixed charges are determined during the annual budget cycle and remain fixed during the year. Variable charges are updated monthly, based on actual hourly costs for fuel.
The cash payment requirements are based on the collection rates of the distribution companies from their customers, and of EETC from the UHV and HV customers it directly serves.
The distribution companies make payments to EETC, which in turn makes payments to the generation companies for the power delivered. The charges to the distribution companies are set at a level that will permit each one to be profitable if well operated. Charges to the customers, including the UHV and HV customers, are based on the uniform national tariff.
The fixed components of charges and all cash payment requirements are determined by the charges model on a forecast basis, based on overall pricing principles and within the framework established by the agreements. These forecast values are then used for determining actual monthly fixed charges and cash payment requirements. The variable components of actual monthly charges are determined based on actual monthly metered values for generation output and cost, and on demand for distribution companies. A different measure of demand is used for each category of charge. For example, the costs of transmission service are shared among the distribution companies based on their forecast peak MVA demand.
The billing and payment system includes meter data collection and reporting, invoices and ledger to track payments and running balances between the companies. Figure 1 shows the computer architecture for this billing system, which will liberalise the data flow and decision process.
At the plant level, production company personnel will use the handhelds to collect the interval meter data from each metering point. This data will be uploaded to the MeterNet database system for review, approval, and transmission to the production company headquarters.
Another copy of MeterNet will reside at headquarters to collect, store, and process the meter data from all plants. Once the plant manager has approved the meter data, it is sent via modem to the production company office for processing. This will occur on a weekly basis and on the first business day of each month. When all the weekly data has been received from the plants, the operator will export the data from MeterNet and import it into the billing and payment system for calculation of fuel use and for invoicing purposes.
Each meter will be associated with a particular unit; a unit may comprise one or more meters summed algebraically. The most common unit definitions will be:
A generator whose net output is measured with a single meter.
A generator whose gross output is measured with one meter while auxiliary loads specific to that unit are measured with another.
Plant loads that are necessary to the functioning of a plant but cannot be assigned to any specific unit. MeterNet is configured at the plant level to aggregate the appropriate meters to form units; it is the unit information that will feed into the billing and payment system.
In the following diagram, Generator 1 and its dedicated auxiliary load have been grouped together to form Unit 1, which is the summation of meter 1 and meter 2. Meter 3 (and possibly more) serves general plant loads and forms a virtual unit.
Delivered and received electricity is recorded separately in each meter and in MeterNet. This simplifies the definition of a unit, since it becomes the sum of each register. In the case of Unit 1, the delivered electricity values from meter 1 and meter 2 are added, as are the received energy values.
The billing and payment system imports the delivered and received values from each unit and calculates the net electricity generated as delivered electricity less the received electricity (auxiliary loads) for each unit. This value will always be negative for plant loads. For thermal generating units, fuel use is calculated based on the hourly net electricity generated using the information for that unit. Each unit has two parameters that are used to calculate the fuel use from the net generated electricity: the no-load fuel consumption (b) and the incremental fuel consumption (m). These are used in an equation of the form Y = MX + B so that the fuel used can be calculated for every hour as follows:
Gas used during the hour, m3 = [% gas] * [ (mgas)(MWnet) + (bgas)] / (LHV, kCal/m3 )
Mazut used, kg = [% mazut] * [ (mmazut)(MWnet) + (bmazut)] / (LHV, kCal/kg )
If solar is used, solar is calculated instead of mazut. The fuel mix needs to be known for every hour, but it defaults to the preferred fuel type for each unit for fail-safe operation. The hourly fuel cost is then the hourly fuel use multiplied by the appropriate fuel cost.
Fuel Cost = (gas use, m3)*(cost, LE/m3) + (mazut use, kg)*(cost, LE/ton) / (1000 kg/ton)
An average cost per net unit of electricity generated is calculated every hour by dividing the fuel cost by the output in MWh. The monthly fuel use and cost is simply the sum of the hourly fuel use or cost.
Gas used during the month = ∑ [hourly gas consumption]
Mazut used during the month = ∑ [hourly mazut consumption]
GRID TRANSFORMER LOSSES
Grid transformers are installed at most generation plants to connect busbars at different transmission voltages. Meters have been installed at these transformers to record the losses so that their costs can be accounted for. Plant personnel will record these meter values monthly and report them to EETC and to the production company headquarters. The production company will calculate the losses and report them in the monthly invoice. The company-wide average production cost will be used to value the losses, but this amount will not be deducted from the allowable fuel cost.
Grid Transformer Loss Value, LE =
Average Production Cost, LE/MWh * Grid Transformer Losses, MWh