Nigeria’s power generation: How far?
Nigeria has 29 on-grid generation stations with a total nameplate/ installed generation capacity of 14, 278 MW. Available generation capacity is approximately 6,500MW on an average. However, actual average generation levels hover between 3,800 MW to 4,700MW with a peak generation of 4,810MW attained in August 2015.
Out of the twenty-nine (29) generation stations, 7 of the generation plants were built before 1999 and owned by NEPA (later PHCN). Four of these stations were built by Rivers State and Akwa Ibom State. The Niger Delta Power Holding Company (NDPHC) accounts for 10 of the power plants, which were built under the National Integrated Power Project (NIPP), while IOCs (Shell and Agip) account for 2 of the plants. Besides the 29 power stations, there are a number of off-grid, captive generation plants with varying generation capacities supplying power on a dedicated basis to several industries and captive municipalities.
Peeling through the numbers, the difference between the name-plate/installed generation capacity and the actual average generation tells the story of generation. The difference can be attributed to a number of the following broad reasons– lack of investment in generation, poor maintenance, gas constraints, transmission constraints, poor water management (for the hydro electric plants) and poor project planning and execution.
Privatisation of successor GENCOS
The privatization of successor PHCN generation companies has to a large extent, restored some lost capacity. For instance, the core investor in Egbin has restored the Egbin power plant to its nameplate capacity of 1,320MW after takeover of the facility. Transcorp Ughelli Power, the core investor in the Ughelli Power Plant (Delta) has restored capacity over 634MW from 160MW at the time of takeover in 2013. Same also with Shiroro, where the core investor has restored the available generation of the station to 450MW. Kainji and Jebba hydros are work-in-progress and hopefully, the core investor, would complete the rehabilitation works of the turbines in good time to restore lost capacity. On the other hand, we’ve lost available capacity as well. AES as well as the three Rivers State IPPs (Omoku, Afam and Trans Amadi) have been unable to come on stream due to gas related issues. More than 1,200 MW of available generation capacity is currently stranded or utilized due to gas constraints.
Notwithstanding, in our view, the generation segment of the electricity value chain has seen steady progress despite daunting challenges and constraints in the power sector. However, if these challenges and constraints are not resolved now rather than later, it could result in stifling further investments by Gencos in capacity recovery and new generation capacity. Nigeria may experience a significant decline in available generation capacity under these circumstances. We enumerate some of these challenges and share our thoughts of how to move the generation segment of the power sector forward.
Resolution of outstanding debts to GENCOS
Power Generators are owed more than N100 billion to date (by our estimates) in accumulated debts for power generated (capacity and energy charges) from November 1, 2013 till date. With the declaration of TEM in February 2015, monthly shortfall payments to Gencos for power generated are in excess of N7 billion monthly. The debts and outstanding payment shortfalls to Gencos are a result of a combination of non-cost reflective tariffs, high distribution losses at the Disco level, low collection efficiency by Discos and in some cases, sharp practices or recalcitrance by some Discos to pay for energy sold. The Regulator undeservedly has a fair share of the blame as well. Regulatory actions (or inactions) by NERC, as the regulator of the power sector could be ascribed as one of the reasons.
In an earlier paper published in April, we argued that Discos would not be able to pay 100% for the energy sold, even with a cost reflective tariff in place. We estimated that it would take between 2 – 3 years for Discos who make the right investments in metering and network optimization, to be in a position to make full payments for energy sold. At the time, we proposed what we called a Local partial risk guarantee (PRG) solution (similar to the World Bank or AfDB PRG instruments) backed by a debt issuance program by NBET, to fund the revenue shortfalls and make payment to Gencos for wholesale power. The local PRG solution was also proposed to address the funding gaps to TCN.
Our view is that the local PRG solution or other bankable and sustainable solution(s) that address the revenue shortfall in the electricity sector should be urgently developed and implemented. Full payment to Gencos for capacity delivered will sustain investments in capacity recovery and also stimulate further investments in additional generation capacities.
Resolving gas constraints
It is pleasing to note that there has been much progress in resolving gas constraints to Gencos. Critical gas infrastructure are about to be completed which would increase gas supply to the power sector. In particular, we understand that a new gas-to-power pricing regime for DSO gas will come into effect within weeks. However, a lot still needs to be done to overcome existing gas constraints. The first step is to address the huge debts and shortfall payments to gas suppliers’ pre and post privatization. Again, the implementation of the local PRG solution for the power sector described above, to resolve the revenue shortfalls is key.
Gas suppliers need to be assured of the credit worthiness of Genco off-takers, demonstrated by timely and full payment of gas bills by Gencos. Secondly, as existing gas constraints are being resolved, it is becoming evident that there is very little DSO gas available for additional generation capacity.
An additional 1,182MMSCF of gas, which is equivalent to 4.3GW of additional generation capacity, will be required if all thermal power units were to come on stream. The Ministry of Petroleum Resources and the NNPC should work in tandem with the power sector to get gas producers to make the necessary investments in the development of proven gas reserves that can provide the sector with additional gas. Lastly, issues of vandalism of gas pipelines needs to be checked and reduced to the barest minimum if the current increase in power generation is to be sustained. However, given the increasing level of terrorism worldwide, diversifying our energy mix to reduce our dependency on natural gas for the bulk of our power generation capacity is the best way to counter such threats and should be a strategic focus for the new power team.
Gas-to-Power pricing methodology
While gas-to-power pricing for DSO gas has been largely resolved and hopefully a new DSO price will soon become effective, some experts have suggested the need for a Gas Regulator to regulate the price of gas to the power sector. This is in view of the almost opaque nature of the methodology used in arriving at the delivery price of non-DSO gas to Gencos. Recent discussions with some gas suppliers for the possibility of supply of gas to a power generation project still in conception, suggest that gas sellers fix non-DSO gas price in an arbitrary manner, subject to whatever price above the DSO price of $2.50/Mscf they believe they can get away with.
Currently, non-DSO gas price range from $3.16 to as high as $6.00/Mscf. While the decision to establish a dedicated gas regulator is within the realm of policy, in the short term, our view is that gas sellers, in determining the price of gas to the power sector, should be subject to the open book process to be reviewed and approved jointly by both NERC and the Department of Petroleum Resources (DPR) before Gas Supply Agreements for non-DSO gas are entered into. Also to be fast tracked is the implementation of the Gas Transportation Network Code, which has been in the works for a while and would result in open access to any gas user or buyer who want to access the system for the purpose of getting gas, as well as (hopefully) cut short the sharp practices prevalent in the current gas supply and distribution system.
Foreign exchange availability for GENCOS
As successor Gencos continue implementing their post-acquisition plans for maintenance, capacity recovery and capacity expansion, it is critical that they are not constrained by the current short term foreign exchange measures put in place by the Central Bank, and have access to foreign exchange to import critical plant machinery and equipment.
Bilateral direct agreements
As available generation capacity increases, it is difficult to understand the rationale behind asking on-grid power plants to put all their available capacity on the grid even when the grid is clearly unable to evacuate the power efficiently to load centres across the country for a myriad of grid and non-grid issues. As a way out, Gencos should be allowed to sell power directly to captive industrial customers of Discos in close proximity to them. Of course the Discos would have to make the investments from a network perspective to ensure a dedicated supply of power from the Genco to such captive industrial customers. By the way, most of these industrial customers are not grid supplied and generate their own captive power at a huge cost to their operations.
To further exacerbate the problem, Gencos are now faced with low absorption of power by Discos (load rejection), thus leading to reduced revenues to Gencos on account of the unutilized available capacity. This is a disincentive to further investments in additional generation capacity. For thermal generation plants, its double jeopardy as feedstock gas is on a take-or-pay basis. One Genco recently shared their experience of having to ramp down and then “flush” gas in its gas pipelines due to non-utilization of the gas. Direct bilateral agreements would reduce such incidences and increase revenues to Gencos.
Resolving transmission and evacuation constraints
Further investments in capacity recovery or new generation capacity would be money down the drain if transmission constraints are not resolved and the wheeling capacity of the grid increased in tandem with available capacity. Beyond building new transmission lines, redundancies need to be built in the existing grid network to ensure full evacuation of power from generators to load centres. For instance, a number of generators on the same evacuation corridor can’t go full on at the same time due to the fact that the transmission lines can only take a limited amount of load from both stations.
The Generation segment of the power sector value chain has made significant progress so far with current available generation capacity set to double by 2017 to about 8GW. However, constraints on the transmission and distribution value chain have continued to deny electricity customers the benefit of increased available generation capacity. Investments in transmission and distribution are lagging behind investments in generation. For further investments in generation to continue, investments in the transmission and distribution must meet up with the pace of investments in generation.
In addition, the power sector must demonstrate a track record of timely and full payments to Gencos (and their gas suppliers) for each megawatt of power generated. A situation where Gencos are owed so much for power generated with no clear timelines as to when the debts will be paid, but are required to continue operating their plants with huge operational losses, is bound to someday result in a national energy crisis.
ODION WESLEY OMONFOMAN
Odion Wesley Omonfoman is an energy consultant and the CEO of New Hampshire Capital Ltd. E-mail: orionomon@outlook.com