“What is ANED and when was it established?”
ANED is the Association of Electricity Distributors, a trade association body that represents the eleven (11) electricity distribution companies (DisCo) in the country. ANED was formally incorporated in January, 2015.
“What is the mandate of ANED?”
ANED’s mandate is to promote the interests of the distribution electricity component of the Nigerian Electricity Supply Industry (NESI), specifically, and the larger sector interests, in general. Such interests include legislative, governmental and regulatory outreach; training, facilitating the setting of industry standards and building consumer awareness on electricity distribution issues.
“Who are the current members of ANED?”
The eleven (11) electricity distribution companies of the country make up the membership of ANED. Click HERE to view members.
“What is the current electricity metering situation?”
The regulator, Nigerian Electricity Regulatory Commission (NERC), reported in July 2017 that there is a total of 7,476,856 electricity consumers, of which 3,439,236 have been metered. Thus, there is a current metering gap of 4,037,620.
“Why can’t I be metered before my tariff is increased?”
Unfortunately, comprehensive metering requires significant capital outlay or investment. Without an appropriate pricing of the production and supply of electricity, which includes the cost of providing meters, distribution companies are unable to access the financing that is fundamental to procuring and installing meters. Providing meters has a cost that must be recovered.
“What would it cost to meet the metering requirement?”
It has been estimated that there is a metering gap of 4,037,620. Under the Meter Asset Provider “MAP” initiative, 3rd party vendors are working with the DisCos to address the metering gap. The price for a single phase meter under the program is about ₦37,000 and for a 3-phase meter, about ₦68,000.
As such, the total cost to address the metering gap will be a product of the number of these 2 types of meters and their respective prices.
“How much CAPEX will be required to meet the need?”
While Capital expenditure (CAPEX) under MYTO-2015 continues to be less than that required by the DisCos for comprehensive metering, it is expected that 3rd party vendor financing provided under the MAP initiative will address this limitation.
“How do we contact the DisCos when there are power issues in our locality?”
Most, if not all DisCos have customer help numbers, e-mail addresses and website information indicated on the bills issued to customers. In addition, flyers containing this information are usually available at vending points and DisCo business units, for customers. Customers can also easily access this information via the websites of the respective DisCos, which are listed under the “Members” selection of this website.
“Why do I get crazy estimated billing for the power that I consume?”
Unfortunately, estimated billing is the one issue that has generated significant complaints from electricity consumers. DisCo operators are very alert to these concerns and are working hard to ameliorate the instances in which consumers receive electricity bills that are not consistent with their consumption. For consumers that are not metered, DisCo operators are mandated to apply only the NERC approved estimated billing methodology and they seek to do so. However, where there are instances of incorrect estimated billings, consumers are encouraged to initiate the process for resolution of the issue by contacting the Customer Care Units of the DisCo operator. Given that the commercial success of any DisCo is directly tied to customer satisfaction, the operators stand ready to resolve all such issues.
“What is the difference between the “Market Tariff” vs “People’s Tariff”?”
The term “People’s Tariff” has been used to describe a tariff that electricity customers are willing to, or should pay. “Market Tariff” defines a tariff that fully recovers the cost of generating and supplying power to customers. The challenge is maintaining a balance between both tariffs, which is the responsibility of the regulator and is a requirement of Section 32.d of the Electricity Power Sector Reform Act, 2005, which states that “To ensure that the prices charged by licensees are fair to consumers and are sufficient to allow the licensees to finance their activities and to allow for reasonable earnings for efficient operation.”
Section 32.e further states that “To ensure that, regulation is fair and balanced for licensees, consumers, investors and other stakeholders.” Clearly, any swing of the tariff pricing pendulum to an extreme, in one direction, holds dire consequences for either the customers or the operator. There must be an equilibrium or balance in the pricing of the tariff.
“Why shouldn’t the operators first invest in improving the distribution network and services before increasing the tariff?”
Electricity operations are very infrastructure heavy and dependant, thus, requiring significant investment. Consistent with universal business practices (even with small businesses), it is typical to borrow money from commercial lenders, to make such investments. This is because it is cheaper (Return on Investment (ROI) on equity is usually higher than that on debt) to borrow and it is exceptional for an operator to have the magnitude of required investment capital readily available (without borrowing), outside of lenders. In addition, the increased cost of financing that is tied to equity funding would have to be passed on to consumers in an increased tariff.
As a result, operators need to be able to access debt financing to make the required investment. However, accessing such financing requires that the operators need to be able to provide cashflow projections (in other words provide information on future revenues) to the lenders, that would show how they would repay the money they have borrowed. Such cashflow projections are directly tied to a tariff that is cost reflective or market priced. The absence of such a tariff means that the operators are unable to borrow the critically need funding for infrastructure investment, that would lead to improved electricity supply.
It is also important to point out that without a tariff that allows the DisCo operators to cover their costs, upstream operators such as transmission, generation and gas suppliers will have no incentive to participate in the sector.
In consideration of the aforementioned information, a condition of the Performance Agreement executed between the DisCo investors and the Bureau for Public Enterprises (BPE), the lead privatisation agent of the Federal Government of Nigeria (FGN) requires the implementation of a cost reflective tariff, as a pre-condition for the operators to meet their performance requirements.
“With the Power Holding Company of Nigeria (PHCN) successor companies privatised, why did the Central Bank of Nigeria provide bailout funds to the DisCos?”
The Nigerian Electricity Market Stabilization Fund (NEMSF) was an intervention fund and not a bailout of the DisCos. To be exact, it was a combination of a loan to the DisCos and payment of historical energy and gas supply liabilities owed by PHCN to suppliers. Indeed, the DisCo-related component of the intervention sought to address the liquidity challenges related to market revenue shortfalls, caused by the tariff not being cost reflective or market priced. DisCos are expected to repay the loan at an interest rate of 10 percent, over the next ten years.
It is critically important to understand that the loan comprises of two parts – a) Historical debt owed by PHCN to power generating and gas supply companies, for energy and gas supplied prior to the privatization of November 1st, 2013, which should have been assumed by the Nigerian Electricity Liability Company, Plc. (NELMCO), a government entity; and b) The market shortfalls owed to the DisCos by electricity consumers, due to the non-cost reflective nature of MYTO 2.0, including some of the electricity supply debt owed by Ministries, Departments and Agencies (MDA). Specifically, of the N210.61 billion NEMSF amount, N58.45 billion or 27.75% was designated for the DisCos, while the balance of N152.16 billion or 72.25% was designated for the GenCos, gas suppliers and industry service providers.
“Consumers are requesting for pre-paid meters. Majority of them have expressed that they are willing to pay for the pre-paid meter. They want to pay for only what they use. Why can’t electricity consumers be provided with these meters?”
As mentioned above, the metering gap is so significant as to preclude ready installation of same comprehensively, from a financial and logistical standpoint. However, there is no industry stakeholder more interested in ensuring that electricity consumers be metered than the DisCo operators. This is because metering allows for certainty of supply and consumption information. It provides certainty of revenue for the operators. Currently, there are several revenue leakages associated with the absence of metering, as well as dissatisfaction of electricity consumers on estimated billing.
Consequently, keeping in mind the financial limitations of the CAPEX assumptions under the DisCos tariffs and the logistical challenges associated with the manufacture and supply of meters for the operators, NERC has introduced the Meter Asset Provider initiative, MAP, which is expected to aggressively address customer demand for meters.
“Why is current energy that is being generated and wheeled worse off than that before privatization?”
Interestingly, power generation has improved from the August, 2010 (pre-privatization) peak of 3,804 MW to the recent new peak of 5,375 MW. Indeed, it is affirmation that we are headed in the right direction, in terms of the objectives of the privatization. With the issuance of the minor review and minimal remittance regulatory order, effective July 2019, it is fair to expect that we will continue to see significant increases in the supply of power, as generators receive all the revenues that are due to them, which allows them to provide security to the gas suppliers for improved gas supply, and provides the enabling environment for the entry of more Independent Power Producers. Increased generation is a significant factor in the reduction of consumer tariff rates.
“Why are consumers still paying for Fixed Charges?”
In acknowledgement of the concerns that electricity consumers have on the issue of Fixed Charges, the DisCo operators have removed Fixed Charges as an element or component of the tariff. All that is billed to consumers is an energy charge. As such, consumers only pay for the energy that they consume.
“Can I reasonably expect that the tariff rates will decrease at some point?”
Yes. As previously stated above, a major component of the new tariff is the CAPEX that is required for making investments that will inject efficiency and improvements in the distribution network. The DisCos are committed to making these investments, as well as meeting the other performance requirements under their Performance Agreement, which should result in a reduction in the cost of supply of electricity, over the next five years. There is empirical evidence, world-wide, of the relationship between such investments (which drive efficiency and increased generation) and the reduction in the cost of electricity. It is projected that the tariff should begin to drop the third year from the implementation of MYTO-2015.
Consumers can also help in the process of making electricity cheaper, by recognizing that electricity is a commodity with a price that must be paid. Refusal to pay the electricity bills, theft of electricity, destruction of electricity supply equipment, etc. all adversely contribute to increased cost of electricity.
“Why do the DisCos reject load?”
DisCos are commercial entities that seek to operate in a viable and sustainable manner. In other words, in addition to a tariff that is not cost reflective, DisCos should not engage in a practice that will worsen the liquidity challenge that currently exists. Thus, if the Transmission Company of Nigeria (TCN) is unable to deliver the energy load in an area where it should deliver it, because it suits or meets its need to stabilize the grid, and that load is going to increase the DisCo’s debt profile, the result is that the DisCo will reject that load.
Secondly, if TCN is constrained by its transmission interface and is not able to deliver the load in a certain part of the country and for grid stablilzation purposes, wheels the energy to some other location, this is load dumping and not load rejection. This is the case of the DisCos in the North, that never receive their MYTO allocated loads. Additionally, tracking of energy flow is GSM driven rather than automated, with a SCADA system. As such, TCN has a limited ability to track energy movement in real time, raising the issue of veracity as to the determination of load rejection or not?
There is also a question of what time frame is being tracked, relative to the conclusion of load rejection? Supply of power more than the DisCos’ requirement, in a non-peak period, may not be labeled load rejection.
“Are the DisCos constrained in their ability to take on more power?”
In 2015, a stress test conducted by TCN concluded that the DisCos have a capacity utilization of 6,288 MW versus the 4,500 MW that is currently being stated. TCN has an available tested capacity of 5,500 MW. To date, the highest energy that has been wheeled out is 4,577* MW, thus, indicating that the DisCos currently have the capacity to take that level of energy and a level that exceeds TCN’s current available capacity.