Nigeria has 27 on-grid generation stations with a total nameplate/installed generation capacity of 14,380MW. Available installed generation capacity is approximately 7,500MW 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 September 2015.
The table below shows the plants and their nameplate/installed capacities as well as the types.
|ON-GRID GENERATION STATIONS||TYPE||NAMEPLATE / INSTALLED CAPACITY (MW)||AVAILABLE GENERATION CAPACITY* (MW)|
|SAPELE||GAS / STEAM||1020||240|
|ALAOJI NIPP||GAS / STEAM||1074||250|
|OKPAI (AGIP IPP)||GAS / STEAM||480||480|
|AFAM VI (SHELL IPP)||GAS / STEAM||642||450|
|OMOKU (RIVERS IPP)||GAS||150||0|
|TRANS-AMADI (RIVERS IPP)||GAS||136||0|
* As at January 15, 2016.
Out of the twenty-seven (27) generation stations, seven 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 two of the plants. Besides the 27 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 available generation tells the story of power 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 privatisation 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 to about 760MW from 160MW at the time of takeover in 2013. Same also with Shiroro Hydro, 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 1, Afam IV & V and Trans Amadi IPP) have been unable to come on stream due to gas related issues. More than 1,200 MW of available generation capacity is currently stranded due to gas constraints.
Notwithstanding, in our view, the power 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
Gencos 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 the Transitional Electricity Market (TEM) in February 2015, shortfall payments to Gencos for power generated are in excess of N10 billion monthly. The outstanding debts and 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 sheer recalcitrance by some Discos to pay for energy sold. NERC as the sector Regulator deservedly has a fair share of the blame as well, due to several regulatory inconsistencies, particularly with the tariffs.
In an earlier paper published in BusinessDay newspapers in April 2015, we argued that Electricity Distribution Companies (Discos) would not be able to pay 100 percent 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 improvement and optimisation to be in a position to make full payments for energy invoices, thus resulting in revenue shortfalls to the sector. To address the arising revenue shortfall within this period, we proposed what we called a Local Partial Risk Guarantee (PRG) solution, similar to the World Bank PRG instrument, backed by a medium term debt issuance programme by the Nigerian Bulk Electricity Trader (NBET), to fund the revenue shortfalls and make full payment to Gencos for wholesale power. The local PRG solution was also proposed to address the funding gaps in electricity transmission.
Notwithstanding the implementation of a new electricity tariff regime on February 1, 2016, our view is that the proposed 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, a new gas-to-power pricing regime for Domestic Supply Obligation (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- privatisation. The N213Billion facility by the CBN is directed at settling outstanding debts to gas producers up until December 2014. Going forward, the implementation of the local PRG solution for the power sector described above, to resolve revenue shortfalls to Gencos and gas producers is imperative to address non-payment to gas producers. Gas producers need to be assured of the credit worthiness of Genco off-takers, demonstrated by timely and full payment of their gas bills. The local PRG solution proposed above will enhance the credit worthiness of Gencos in this regard.
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 and possibly the CBN or the financial community, 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 need 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.
Competitive and Transparent 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 determine and regulate gas prices to the domestic market and the power sector. This is in view of the arbitrary and almost opaque nature of the methodology used in arriving at the delivery price of DSO and 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 producers and suppliers 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 $3.50 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 producers, in determining the price of gas to the power sector, should be subject to an 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 producer or buyer who want to access the gas pipeline 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 to Import Critical Machinery and Equipment
As privatised 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 foreign exchange measures put in place by the Central Bank, and have access to foreign exchange to import critical plant machinery and equipment. Ramping up available generation capacity would reduce fuel imports significantly and save scarce foreign exchange, besides other multiplier effects to the economy.
Bilateral Direct Agreements Between Gencos and Discos for Wholesale Power
It is difficult to understand the rationale behind asking on-grid power plants to put all their contracted 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 stranded contracted power directly to Discos or captive industrial customers of Discos in close proximity to them. Most of these industrial customers are not grid supplied and they generate their own captive power at a huge cost to their operations. For instance, large conglomerates such as Dangote, Guinness, Larfarge, British American Tobbaco, Nigerian Breweries and Coca Cola run their own off-grid power generation plants and in some cases, even supply the grid with excess power. The recent decision by Egbin Power Generation to enter into bilateral power supply agreements with Eko Disco and Ikeja Disco for additional 220MW to the Lagos area is a step in the right direction. Other Gencos with stranded available generation capacities should be encouraged to adopt this model as well.
Improve the Ability of Discos to Absorb More Power
Unbelievably, the recent improvement in power generation to a mere 4,000 MW on the average, has seen an increase in cases of Discos rejecting power from Gencos (load rejection), thus leading to reduced revenues to Gencos on account of the unutilised available capacity. This is a huge disincentive to further investments in capacity recovery and additional generation capacity, as it makes no sense for a Genco to increase its available generation capacity when Discos will reject such power. For gas Gencos, it is double jeopardy as feedstock gas is on a take-or-pay basis, meaning the Genco must pay for the gas irrespective of the gas being utilised or not. Consequently, Discos must make the necessary investments to improve their ability to absorb more power from the grid. In addition, Discos must also focus on improving their collection efficiency and revenue generation profile through adequate metering of their customers.
Resolve Transmission 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 Gencos on the Afam–Onitsha transmission corridor can’t go full on at the same time due to the fact that the existing transmission lines can only evacuate a limited amount of load from the Gencos operating at the same time.
Conclusion of the NIPP Privatisation
In line with the power sector reforms, the privatisation of ten generation companies owned by the Niger Delta Power Holding Company (NDPHC) and built under the National Integrated Power Projects (NIPP), commenced in 2013. Preferred Bidders emerged with the financial bid opening stage concluded in March 2014. Under the terms of the transaction, the Government will retain a 20 percent ownership of the NIPP Gencos while Preferred Bidders will own 80 percent shares and be responsible for operating the Plants in an efficient manner.
It is imperative for the National Council on Privatisation (NCP) to continue with, and conclude the sale of the ten NIPP Gencos to Preferred bidders in the quickest possible time. The privatisation of the 10 NIPPs has dragged on for two years with no seeming headway as a result of gas issues and negotiation of some key transaction conditions, such as the Federal government providing investors with bankable agreements.
The sale of the NDPHC, expected to generate over US$5.8billion in revenues to the three tiers of government, is critical to unlocking more than 3,000 MW of stranded power from the NIPPs and increasing Nigeria’s available power generation to 7,000 MW by 2017. More importantly, privatisation of NIPP Gencos is the much needed catalyst for ramping up and growing the gas-to-power value chain as NIPPs become credible off-takers to gas producers.
Diversify our Power Generation Mix
Diversifying our energy mix is key to Nigeria’s energy security and by inference, our national security. A situation where more than 85 percent of Nigeria’s installed and available generation capacity is from gas fired Gencos located along the South-East, South-South and South-West corridor is a national security issue. The recent bombing of the Escravos-Lagos Pipeline System (ELPS), the major gas pipeline artery that delivers natural gas to a majority of power stations in Nigeria, highlights this national security risk.
In addition, the current generation mix is not efficient as power generated along this corridor is transported long distances to load centres across Nigeria, leading to transmission losses, grid instability and inefficient dispatch of power.
The Minister and his team must come up with, or rejig existing power generation policies on coal fired thermal plants, hydro plants, and other forms of renewables with the strategic focus on fast tracking on-going, non-gas fired power generation projects such as the Zuma coal IPP, hydropower generation projects such as the Mambila and Zungeru hydro projects and a number of solar power generation projects being sponsored by the private sector. The power generation policies by the Ministry of Power should also stimulate the promotion of new small-scale hydropower generation plants across Nigeria, and renewable energy from solar.
Besides ensuring energy security and increasing power generation from a diverse mix of energy sources, there are direct economic spin-offs and positive multiplier effects. A 300 MW coal fired plant provides natural off-take for the coal industry and would stimulate the coal mining industry, which is almost comatose. Damming rivers to build small hydro generation plants would create river basins and aid irrigation for all year round farming for the communities that surround these dams and rivers. This would boost our agricultural production. Solar energy installations would create jobs and electrify rural communities not served by grid power in rural communities in the north, plagued by insurgency. There is also nuclear energy as well but our view is that these other forms of energy are low hanging fruits that can be embarked upon now with visible results before the next election cycle.
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 7GW. 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 Omonfoman is an energy consultant and the CEO of New Hampshire Capital Ltd. Please send comments to firstname.lastname@example.org.