By Adeniyi Adeoloye
The Nigeria power sector is encumbered right through the entire value chain.
The figures for installed generation capacity, the grid transmission, and what the distribution companies can deliver to the end users, are common knowledge. But there’s a vast gulf between the capacity and the delivery and the specific details of this gap is absent from the conversation.
Many have dismissed the transmission segment as the weak link in the power industry value chain. The call has led to pleas for government to let go of operating it in order to drive efficiency and deliver optimum value. There has been a scathing searchlight on the distribution and transmission links of the sector. But then, the generation segment is as broken.
Nigeria, like many countries, organises its energy mix around energy sources that are abundant within its borders. Hydro power and gas fired plants dominate the energy mix in Africa’s most populous country. Save for the emissions during their construction and location outside demand centres, hydro is largely seen as a clean means of power generation. On the other hand, gas has been given green credentials by the European Union due to its less polluting nature than coal and since labelled a transition fuel. So by and large, the grid emission factor of the power generation systems in Nigeria based on energy source are in relatively good stead.
What are the numbers like? By the tally, there are 23 power generating plants connected to the grid in Nigeria with installed capacity of 10,396 MW and available capacity of 6,056 MW. Of this, gas fired plants account for 8,457.6 MW with available capacity of 4,966 MW while the remainder is hydropower with installed capacity of 1,938.4 MW and available capacity of 1,060 MW. The large chunk of the country’s generation is gas fired. The ownership of these plants cuts across government and the private sector. Nigerian Bulk Electricity Plc (NBET) undertakes Power Purchasing Agreement (PPA), with the generating companies and sells the energy purchased to the distribution companies via Vesting Contracts. A total of 16 generation companies have PPA with NBET.
Performance of Government Run Power Plants
Government hatched the National Integrated Power Project (NIPP) in 2004 in a bid to stabilize electricity supply in anticipation of the takeoff of the private sector led structure of the Electric Power Sector Reform Act (EPSRA) of 2005. The primary idea of NIPP was to build 7 medium sized gas fired power plants in gas producing states alongside crucial transmission infrastructure required to move the added power to the national grid. The Niger Delta Power Holding Company Limited (NDPHC) was set up to house and manage the NIPP assets with market oriented practice. Available information by NDPHC indicates it owns 10 thermal plants – Calabar (563 MW), Omotosho (500 MW), Sapele (450 MW), Egbema (338 MW), Omoku (225 MW), Alaoji (960 MW), Ihovbor (450 MW), Gbarain (225 MW), Gerugu (434 MW) and Olorunsogo (675 MW). Of this ten, eight of them except Egbema and Omoku have “interim agreement” with government owned Nigerian Bulk Electricity Trading Plc (NBET) that buys power from Independent Power Producers (IPP) and successor generation companies from the unbundling of Power Holding Company of Nigeria (PHCN) and resale to Distribution Companies who deliver to end users and other large consumers who take electricity directly from the grid.
The eight plants having interim agreements with NBET have total contract capacity of 4,257 MW and tested capacity of 1762 MW with average generation capacity of 488.15 MW as at year 2021 according to data by NBET. The data further shows average generation of these plants is a paltry 11% of net contract capacity, and about 27% of tested capacity. Plants with installed contract capacity of 500 and above didn’t perform any better. Alaoji with net contract capacity of 960 MW and tested capacity of 212.33 MW averaged an output of 58. 19 MW. Olorunsogo (675 MW, 212.67 MW and 23.07 MW), Calabar (563 MW, 339.55, 236.02) and Omotoso (500 MW, 219.61 MW and 43.24 MW) for net contract capacity, tested capacity and average generation capacity respectively. The Ihovbor Plant with contract capacity of 450 MW and tested capacity of 202.34 MW last done in 2021 had average generation capacity of 16.87 MW in year 2021. This is an abysmal low of capacity utilisation. Across board, NDPHC managed plants are poorly performing.
And talking about testing, the data also established year 2015 as the last test date for all NDPHC plants with the exception of Alaoji plant whose capacity test was carried out in June 2021. The lag in test capacity is against what is stated in a March 2022 draft power purchase agreement for brownfield power plants by NBET which states “the Tested Capacity of the Plant shall be verified at least annually by further Capacity Tests that will establish the revised Tested Capacity”. Usually there are diverse reasons to appraise the performance of a plant other than meeting contract guarantees. Performance tests for a brownfield power plant can be done to verify its capacity and heat rate before an acquisition in order to determine its asset worth. Testing is also useful for the goal of maintaining a Power Purchase Agreement, tariff up-gradation as well as to ascertain the performance differences brought by major repairs or component upgrades.
Review of Successor Gencos
Successor Gencos are power generation companies created in the aftermath of the unbundling of PHCN. There are eight of these plants around the country namely: Kainji (760 MW), Jebba (576 MW), Shiroro (600 MW), Egbin (1100 MW), Sapele (1020 MW), Delta (900 MW), Afam IV-V (776 MW) and Gerugu (414MW). Tese are nameplate capacities. With the exception of Kainji, Jebba and Shiroro that are hydro power, the rest are gas fired. Many of the plants have been fully or partially sold, and others under long term concession. All of the plants have Power Purchase Agreement with NBET with total contract capacity of 6,146 MW, last tested capacity of 2,853.72 MW and average generation capacity of 2,010.4 MW in year 2021. The average generation capacity of these plants is 32% of contract capacity and 70% of tested capacity. On a plant by plant basis, the Sapele plant is an overwhelming underperformer given its contract capacity of 1020 MW and test and 2021 average generation capacity of 52.29 MW and 46.39 MW, being last tested in June 2021. This translates to a miserly 4.5% average generation capacity to contract capacity. Afam IV-V didn’t fare any better with contract capacity of 776 MW and test and average generation capacity of 121.9 MW and 66.75 MW respectively and last tested in July of 2021. For context, the output from Afam IV-V is a beggarly 8.6% of its contract capacity.
Test dates for the plants was between June and August 2021. Over two years ago. Still far behind the annual recommendation of NBET. The performance of plants in this category outmatch those of the NIPP plants managed by NDPHC despite the sub par productivity of Sapele, Kainji, and Afam IV-V respectively.
A look at Plants in other Categories
There are five plants that are classified by NBET as having active PPA namely: Okpai operated by Agip, Afam VI run by Shell, Omotosho Electric, Olorunsogo and Azura Edo IPP. All of these plants are gas fired with total contract capacity of 2,188 MW, tested capacity of 1,815.61 MW and average 2021 generation capacity of 1,338.68 MW. The average generation capacity of these plants with respect to tested capacity is 71% and 61% with respect to contract capacity – an indication of better performance. Of plants in this category, Azura Edo IPP with contract capacity of 450 MW and test capacity of 452.6 MW and average generation capacity in 2021 at 420.84 outperforms it peers. In context, average generation capacity with respect to test capacity and contract capacity stands at 92% respectively with last capacity test carried out in June 2022. Shell run Afam VI has contract capacity of 650 MW, tested capacity of 464.96 and average generation capacity of 261.04 MW in 2021 with last test date of July 2021. In performance terms, the average generation capacity with respect to contract capacity and tested capacity stands at 40% and 71% respectively. For Agip run Okpai with contract capacity of 480 MW, it tested capacity is 464.96 MW with average generation at 261.04 MW. Last tested in July 2021. This translate to 56% and 54% of average generation capacity with respect to tested capacity and contract capacity respectively. Without doubt, Azura leads the pack in terms of production efficiency.
State Government owned plants Ibom Power, Mabon, Omoku FIPL, Trans Amadi FIPL, AFAM (Rivers IPP) FIPL, and Eleme have combined contract capacity of 870 MW, with tested capacity of 451.88 and average generation of 185.09. The average generation capacity of Ibom power of 12.53 MW compared to test and contract capacity of 112.83 MW and 190 MW respectively, translating to 11% of average generation to test capacity is an indication of operation plunging into an abysmal depth. The Mabon and Eleme are new plants in the inventory of NBET with their capacity test yet to be carried out.
The foregoing is the state of things with the plants based on data from NBET. Cash liquidity constraint is a major issue given collection inefficiency by distribution companies. This has a ripple effect on the sector, leading to inability of operators to pay gas producers. Additionally, the insufficiency of the transmission company to transmit contracted or test generation capacity due to infrastructural gap and vandalism has left the country with more than 20 plants with test capacity of 6,884.76 MW out of contract capacity of 13,461 MW and an average generation of 4,022 MW in 2021 to back up power from the grid with gasoline or diesel generators. The factors causing this inefficient operations has to be reigned in rather than pushing the much needed reform to turn things around into the long grass as done by successive governments. Economic growth, its attendant job creation and prosperity will continue to be an illusion with this sort of underwhelming productivity of the power generating plants.
“Key Parts of a Power Purchase Agreement” According to NBET
Tariff Structure – Provides the details of how NBET will pay for the duration the PPA is calculated.
Risk Allocation – Identifies all project related risks and allocates these risks to parties best able to bear them.
Conditions Precedent – Provides all the conditions precedents (CPs) which either the Buyer (NBET) or Seller (Owner of plant) must satisfy before the PPA can become effective.
Tenor of PPA – A standard NBET PPA has a 20 year tenor. There are clauses within the PPA to handle early termination due to either a Buyer’s or Seller’s default.
Project Documents – All documents that are connected to the PPA such as Engineering, Procurement and Construction, Gas Supply Agreement (GSA), Gas Transport Agreement (GTA), Operations and Maintenance, Long Term Service Agreement, Financing documents e.t.c.
Commissioning & Testing Procedure – Contains a set of guidelines for plant testing and commissioning.
Operation & Maintenance – Contains details of the maintenance and operational obligations of the Seller throughout the tenor of the PPA.
Conflict Resolution – Indicates clear procedures for conflict resolution in case of disputes and/or conflicts on invoices.
Metering – Sets out the rules about metering. However, in case of conflicts between PPA provisions and the metering code, the metering code supersedes.
Liability & Indemnification – Enumerates the parties responsible for certain failures and provides indemnification to both parties.
Insurance – States the required insurance coverage to be put in place by the Seller and how the proceeds will be administered.
Scheduling Notices – Provides a methodology by which the Buyer nominates for the dispatch of Net Electrical Output to be made available at the delivery point by the seller.
Force Majeure – Provides details of events to be considered as force majeure and possible payments during the occurrence of such events.
Adeniyi Adeoloye is a consulting Editorial associate at the Africa Oil+Gas Report.
“An optimized contracting cycle is poised to enhance the ease of conducting business, lower costs, and drive efficiency, ultimately leading to increased production, higher revenues, and improved profitability”, according to a statement issued after the signing.
