The retail electricity tariffs are adjusted bi-annually to adjust for changes in inflation rate and the official exchange rate of the naira to the dollar. Any increase or downward movement in these two macro-economic indices will increase the price of generation tariffs, transmission tariffs, and consequently end-user electricity tariffs. The converse holds true as well.
Determining Transmission Tariffs Under MYTO
The Transmission grid system includes the physical transmission infrastructure (transmission lines, pylons and substations) that evacuates electrical power from the GENCOs to the DISCOs, and the operations and management of the entire grid system (system operations). It also includes administration of the electricity market (market operations) and provision of specialised ancillary services (frequency control, spinning reserves, black start services, etc).
Transmission tariffs are captured under a charge called the Transmission Use of System (TUOS) charges. NERC has used a building block model in setting transmission and distribution tariffs. The building block model is a form of public utility regulation that is used to determine the allowable revenue requirement of the regulated entity based on the sum of the following components (blocks):
a. The allowed return on capital – being the fair rate of return on capital/investment based on the value of the asset base as well as additional capital investments;
b. The allowed return of capital (also known as depreciation) – based on depreciation cost of the assets in service and calculated using the Depreciated Optimised Replacement Cost (DORC) method of depreciation;
c. Efficient operating costs and overheads;
d. Taxes and incentive mechanisms.
Following from the above building blocks, the following cost assumptions and inputs are used in determining transmission tariffs:
| Cost / Input Assumptions | Explanation |
| TCN Regulatory Asset Base | Initial value of the asset base of TCN as at 2012 and adjusted every year for additions. |
| Cost of Capital | Determined by using the Weighted Average Cost of Capital (WACC) methodology |
| Network / Capital expenditure program for TCN | MYTO 2015 projects total capital expenditure by TCN of about N1.36 Trillion over the next five years starting from 2016. |
| Return of Capital | Depreciation costs for TCN’s regulatory asset base and additional assets financed from capital expenditure |
| Operational expenditures | Annual operations and maintenance costs (fixed and variable O&M costs) and administration costs of TCN (TSP, SO and MO) |
| Transmission losses | Line/equipment losses arising from the transmission of electricity through the grid. |
| Macro Economic Indices | Macro economic indices are Inflation rate (using Nigerian CPI and US CPI) and the foreign exchange rate at the official market. These macro-economic indices are used as escalators to adjust the tariffs in line with changes in these indices. |
| Institutional Charges | Market Participants are required to pay a number of institutional charges in order to enhance the effective regulation and administration of the electricity market. These charges are the regulatory Nigerian Electricity Regulatory Commission (NERC) charge, system operation (SO) charge, market operation (MO) charge and payment for ancillary services. |
Source: NERC MYTO 2015 Tariff Order
The annual revenue requirement for transmission arrived at from the cost assumptions and inputs above is then divided by the forecast level of energy transmitted on the Transmission Company of Nigeria (TCN) network and delivered to Discos and other TCN customers to arrive at the TUOS charge per unit of transmitted energy (Naira/MWh). Average TUOS charges under MYTO 2015 is N3,815/MWh based on a projected average annual generation capacity of 8,707 MW.
Actions of Inflation and Devaluation of the Naira on Transmission Tariffs
The transmission tariffs are adjusted bi-annually to allow for changes due to inflation rate and the official exchange rate of the naira to the dollar. Any increase or downward movement in these two macro-economic indices will increase the price of transmission tariffs (and consequently end-user electricity tariffs). The converse holds true as well. A reduction in inflation rate and strengthening of the naira will reduce end-user electricity tariffs.
Determining Distribution and Retail Tariffs
As previously stated, the revenues to cover the cost of the entire electricity sector come from retail tariffs. Retail tariffs (DISCO Tariffs) cover the following costs:
• Payment for electricity supplied into the distribution network;
• TUOS charge for MW/h delivered to bulk supply points;
• Disco’s cost of distributing through its network;
• Retail costs: marketing, metering, billing and collection;
• Capital expenditure for network reinforcements and new installations;
• Overhead and administrative expenses.
Costs and Input Assumptions for Distribution Tariff Building Block
The building block model explained above is used in setting transmission and distribution tariffs to determine the revenue requirement. The assumptions and cost inputs to determining the building block for determining the revenue requirement of each of the eleven Discos are as follows:
| Cost / Inputs | Explanation |
| Disco Regulatory Asset Base | Initial value of the asset base of Discos and adjusted every year for capital additions. |
| Cost of Capital | Determined by using the Weighted Average Cost of Capital (WACC) methodology and covers the cost of debt, the cost of equity, allowable gearing ratio (debt/equity ratio) and corporate tax. |
| Return on Capital | The cost of capital included in the MYTO is intended to provide a return on existing assets and appropriate incentives for future investment. |
| Annual capital expenditure for each disco | Capital expenditure includes expenditure on metering, network improvement, expansion and other capital costs of Discos. These capital expenditures are added to the Disco regulatory asset base to give the annual asset value of Discos.
Capital expenditure for Discos is regulated as any increase in the annual asset value beyond the allowable capital expenditure impacts the tariffs and has to be recovered from retail tariffs. |
| Return of Capital | Depreciation rate applied to Discos’ regulatory asset base and asset additions from annual capital expenditure |
| Projected Generation Capacity | This is a very significant variable in tariff determination as the revenue requirement of the entire system is based on projected generation capacity from all Gencos.
Projected daily gross generation capacity for 2016 is 5.4GW, 2017 is 7.2GW, 2018 is 8.9GW, 2019 is 10.5GW and 2020 is 11.38GW. To ensure there is no disequilibrium, periodic minor reviews of the tariff will take into consideration changes/fluctuations in the generation capacity and adjust the tariffs as appropriate.
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| Energy Allocation to Discos | This is the percentage amount of total generation capacity on the grid that is allocated to Discos. Given the fact that there is insufficient generation capacity and transmission grid inadequacy that affects all Discos, energy made available into the grid has to be allocated on some fair, transparent and easily understandable basis to Discos. The average estimated energy allocation to a Disco from the grid is about 11%. Each Discos tariff is tied to its estimated energy delivered. |
| Aggregate Loss levels | This covers aggregate technical and non-technical losses and the reduction in established baseline losses over a five-year period based on the annual percentage reduction committed to by each Disco during the privatization stage. |
| Repayment of CBN Facility and accrued Interest | The portion of the tariffs set aside for the repayment of the N213billion commercial loan facility provided by the CBN to the power sector in 2014. The loan has an interest rate of 10% per annum and will be paid by electricity customers over a ten (10) year period. Interest on the CBN loan is over N107 billion thus bringing the total CBN facility amount to be paid by electricity customers to circa N320billion. |
| Distribution Costs (Operating Expenses) | These are costs that cover the Disco’s share of the cost of generation and transmission, as well as distribution/retail cost for individual Discos covering their running costs (operation, maintenance, administration, metering and billing) with the return on capital and the return of capital (depreciation).
The tariffs provide allowance for Discos to cover reasonable administrative, operational and maintenance costs such as salaries and allowances, pension costs, workman compensation insurance and staff welfare. It also provides for funds required to carry out both routine and unscheduled maintenance of all sub-stations, transformers, lines and cables (underground and overhead) and ensure regular line tracing and vegetation control. |
| Institutional Charges | Discos are required to pay a number of institutional charges to facilitate the costs of running the NESI. These institutions are – NERC charges, Market Operator charges, System Operator charges and NBET (Bulk Trader) charges. |
| Customer Population and growth rate | Customer population is a very important variable in determining retail electricity tariffs. The Retail tariffs, as required by Section 76(2), EPSRA, must reflect the costs associated with providing service to each customer, plus a reasonable return. Thus customer population and growth rate impacts Discos ability to earn their revenue requirement. |
| Customer Classification | Customer classification or tariff class is a way to recover the revenue requirement across different customers within a Disco. Customer classification (who pays what) is the responsibility of the Discos. There are five (5) existing customer tariff classes – Residential Customers (R class), Commercial Customers (R4 and C class), Industrial Customers (D Class), Special Class and Street lighting (S class). However, NERC has provided the latitude for Discos to create additional tariff sub-classes or re-categorize sub-classes |
| Changes in Macro Economic Indices | The following macro economic indices are assumed in the tariffs:
• Inflation – the inflation rate of 8.3% is assumed based on the data from the National Bureau of Statistics (NBS) as at October 2015. • Exchange Rate -An exchange rate of N197 to US$1.0 is assumed plus a premium of 1% above CBN rate. • US rate of inflation – the US rate of inflation of 0.2% as at October 2015 is assumed. • Gas Price – A new gas price of $2.50/MMBTu and gas transportation cost of $0.80/MMBTu is applicable. |
The diagram below depicts the process by which retail electricity tariffs are derived using the inputs and cost assumptions.
Retail Tariff Design
There are eleven DISCOs in Nigeria. Each Disco has tariffs reflecting it uniqueness in terms of cost, location and customer profile. The retail tariff has two charges namely:
• Energy Charge (N/KWh): This charge is for the volume of electricity consumed by a customer and expressed in naira/KWh consumed;
• Fixed Charge (N/Month): Is intended to recover fixed costs, which all electricity consumers bear regardless of their consumption. The fixed charge component of retail tariff has now been removed by rebalancing it to the energy charge to reflect the wishes of stakeholders in the industry.
The Impact of ATC&C Losses on Tariffs
ATC&C means Aggregate Technical, Commercial and Collection Losses. In any electrical system, losses are inevitable as electrical energy is transferred across transmission and distribution networks. In addition, not all energy delivered to DISCOs is billed and when energy is billed, it may not be collected. Distribution Losses are categorised as follows:
• Technical Losses – Losses as a result of the transfer of electrical energy across transmission and distribution networks;
• Commercial Losses – Losses that arise as a result of electricity delivered not billed due to either theft or wrong billing practices;
• Collection Losses – Energy billed but revenues not collected.
Average ATC&C losses for DISCOs are about 42 percent to as high as 60 percent. This simply means that DISCOs lose more than 45 percent of their revenues for every kilowatt-hour (Kwh) of energy they receive. In addition, high commercial and collection losses mean higher retail tariffs as only a few customers are actually paying for the revenue requirement of the power sector.
Reducing ATC&C losses increases the revenues to a Disco (and hence, the power sector). In addition, reduction in ATC&C losses also has a direct relationship with the electricity tariffs. As losses are reduced, the retail electricity tariffs also reduce as well.
During the privatisation of the DISCOs, the sole basis for selecting Preferred Bidders was highest percentage ATC&C loss reduction trajectory over a five-year period. Now that new electricity tariffs have been approved and hopefully has come to stay, the Federal Government and NERC must ensure that the annual ATC&C loss reduction percentages committed to by Discos during the privatisation are met.
Actions of Inflation and Devaluation of the Naira on Retail Electricity Tariffs
The retail electricity tariffs are adjusted bi-annually to adjust for changes in inflation rate and the official exchange rate of the naira to the dollar. Any increase or downward movement in these two macro-economic indices will increase the price of generation tariffs, transmission tariffs, and consequently end-user electricity tariffs. The converse holds true as well. A reduction in inflation rate and strengthening of the naira will reduce end-user electricity tariffs. (To be continued).
Odion Omonfoman is an energy consultant and the CEO of New Hampshire Capital Ltd. Please send feedback to orionomon@outlook.com.
