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NIGERIA POWER SECTOR PROGRAM
LONG-TERM PLANNING ASSESSMENT
April 2019
DISCLAIMER:
This publication was prepared for review by the United States Agency for International Development. It was
prepared by Deloitte Consulting LLP. The author’s views expressed in this publication do not necessarily reflect
the views of the United States Agency for International Development or the United States Government.
LONG-TERM PLANNING ASSESSMENT ii
NIGERIA POWER SECTOR PROGRAM
(NPSP)
LONG-TERM PLANNING ASSESSMENT IDIQ Contract No. 720-674-18-D-00003 Power Africa Extension (PAE)
Task Order No. 720-674-18-F-00003 Nigeria Power Sector Program (NPSP)
USAID | Southern Africa
Contracting Officer’s Representative: John Garrison
Contributors: Yousef Majzoub
Reviewers: Colin McCollester and Grayson Heffner
Submitted:
ACKNOWLEDGEMENT:
This document was produced for review by the United States Agency for International Development. It was
prepared under Task Order No. 01: The Nigeria Power Sector Reform Program (the “Task Order”) of the
Power Africa Indefinite Delivery, Indefinite Quantity (“IDIQ”) Contract No. 720-674-18-D-00003 implemented
by Deloitte Consulting LLP.
LONG-TERM PLANNING ASSESSMENT iii
ACRONYMS
Acronym Definition
DISCO Distribution Company
EPSRA Electric Power Sector Reform Act
FGN Federal Government of Nigeria
GAR Generation Adequacy Report
GENCO Generation Company
JICA Japan International Cooperation Agency
MYTO Multi-Year Tariff Order
NARUC National Association of Regulatory Utility Commissioners
NBET Nigerian Bulk Electricity Trading PLC
NERC Nigerian Electricity Regulatory Commission
PPA Power Purchase Agreement
RAM Review, Approval, and Monitoring
TCN Transmission Company of Nigeria
TEP Transmission Expansion Plan
LONG-TERM PLANNING ASSESSMENT iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY ................................................................................................................................. 1
PURPOSE OF THE ASSESSMENT ....................................................................................................................... 1
CURRENT STATE OF LONG-TERM PLANNING ......................................................................................... 1
CONSEQUENCES ARISING FROM LACK OF LONG-TERM PLANNING ........................................... 1
1. INTRODUCTION ................................................................................................................................... 3
1.1 BACKGROUND AND CONTEXT........................................................................................................... 3
1.2 PURPOSE AND STRUCTURE .................................................................................................................... 3
2. SYSTEM PLANNING ............................................................................................................................... 5
2.1 OVERVIEW ...................................................................................................................................................... 5
2.2 KEY CHALLENGES AND IMPACTS ......................................................................................................... 7
3. LOAD DEMAND FORECASTING ................................................................................................... 12
3.1 OVERVIEW .................................................................................................................................................... 12
3.2 KEY CHALLENGES AND IMPACTS ....................................................................................................... 14
4. DISTRIBUTION EXPANSION PLANNING ................................................................................... 16
4.1 OVERVIEW .................................................................................................................................................... 16
4.2 KEY CHALLENGES AND IMPACTS ....................................................................................................... 18
5. TRANSMISSION EXPANSION PLANNING .................................................................................. 20
5.1 OVERVIEW .................................................................................................................................................... 20
5.2 KEY CHALLENGES AND IMPACTS ....................................................................................................... 23
6. GENERATION EXPANSION PLANNING ..................................................................................... 24
6.1 OVERVIEW .................................................................................................................................................... 24
6.2 KEY CHALLENGES AND IMPACTS ....................................................................................................... 27
7. CONCLUSION ...................................................................................................................................... 29
LONG-TERM PLANNING ASSESSMENT v
LIST OF TABLES
TABLE 1: KEY TAKEAWAYS......................................................................................................................................... 2 TABLE 2: PLANNING HORIZONS ............................................................................................................................. 8 TABLE 3: CURRENT TCN FORECAST FACTORS VS. GRID CODE FORECAST FACTORS ................. 13 TABLE 4: CURRENT DISCO FORECAST APPROACH ...................................................................................... 14 TABLE 5: DISCO EXPANSION PLAN VS. REQUIRED DISTRIBUTION CODE ATTRIBUTES ............... 17 TABLE 6: DISTRIBUTION CODE (PART 2) SECTIONS GOVERNING DISCO PLANNING .................. 18 TABLE 7: SYSTEM ADEQUACY REPORTS CURRENT METHODOLOGY OVERVIEW ........................... 21
LIST OF FIGURES
FIGURE 1: NIGERIA POWER SYSTEM PLANNING OVERVIEW ....................................................................... 6 FIGURE 2: CURRENT SYSTEM PLANNING STATUS AS OF NOVEMBER 2018 ........................................... 7 FIGURE 3: APPROXIMATION OF CURRENT IDLE INFRASTRUCTURE CAPACITY .............................. 10 FIGURE 4: LOAD FORECAST PROCESS GAPS ..................................................................................................... 12 FIGURE 5: DISTRIBUTION EXPANSION PLAN MARKET RULES PROCESS ............................................... 16 FIGURE 6: TRANSMISSION EXPANSION PLAN PROCESS .............................................................................. 20 FIGURE 7: TRANSMISSION EXPANSION PLAN (FICHTNER) OVERVIEW ................................................. 22 FIGURE 8: TRANSMISSION EXPANSION PLAN GRID CODE PROCESS .................................................... 23 FIGURE 9: EXISTING AND PROPOSED GAS TRANSMISSION INFRASTRUCTURE ................................ 25 FIGURE 10: GENERATION EXPANSION PLAN PROCESS ............................................................................... 26
LONG-TERM PLANNING ASSESSMENT 1
EXECUTIVE SUMMARY
PURPOSE OF THE ASSESSMENT
The Long-term Planning Assessment seeks to identify current shortcomings of Nigeria’s long-term energy
system planning mechanisms and suggest potential improvements. Long-term energy system planning
mechanisms can ensure that future load demand is reliably supplied by generating units at the lowest
possible cost to consumers. Long-term planning also ensures that waste and idle capacity, in generation,
transmission, and distribution, is avoided by aligning interests of different stakeholders in the value chain.
CURRENT STATE OF LONG-TERM PLANNING
The Nigerian Electricity Regulatory Commission (NERC) has recently called for the submission of
transmission and distribution expansion plans to enhance overall power system planning. Until now, the
Nigerian power system has operated without the benefit of any type of industry-wide accepted plan. Each
part of the power value chain has been planned in relative isolation, with investments and expansions
carried out on an ad hoc basis without consideration for other parts of the value chain. Power projects
are accepted on an unsolicited basis from many developers, leading to an incoherent system with many
infrastructure gaps and bottlenecks. The Nigerian power system has generation capacities that are severely
underutilized and will only become dispatchable when transmission and distribution bottlenecks are
relieved to meet incident load growth. Despite these bottlenecks, there are also areas where transmission
and distribution infrastructures are underutilized. In many cases, mismatches at the interface between the
transmission and distribution systems, cause either distribution capacity or transmission capacity to be
underutilized. In addition to planning issues affecting electricity infrastructure, the lack of coordination in
developing generation investments has resulted in non-operational generating units due to gas
transmission constraints (e.g., pipeline size).
CONSEQUENCES ARISING FROM LACK OF LONG-TERM PLANNING
The lack of planning coordination among the various stakeholders of the power value chain has resulted
in an inefficient allocation of resources in network infrastructure development. Consequently, the
mismatch of capacity along the power sector value chain has resulted in bottlenecks and surplus capacities
ultimately limiting the average energy delivered to end users to approximately 4,000 MW1. This has an
adverse effect on total system cost, since underutilized/surplus capacities may be considered as part of
the asset base during tariff determination. In order to ensure the reliability of the power grid system in
the long-term, Nigeria’s long-term energy system planning mechanism must be strengthened by formalizing
a planning framework, engaging stakeholders by ensuring the provision of economic incentives, and
improving the technical capacity of stakeholders to carry out planning activities. See Table 1 below for a
summary of the different challenges, their causes, potential interventions to address them, and expected
outcomes.
1 NERC Quarterly Reports
LONG-TERM PLANNING ASSESSMENT 2
Table 1: Key Takeaways
Problem Causes Actions for Change Outputs
Misallocation of power
sector financial and
infrastructure resources
No integrated system planning mechanism in
place
NERC to formalize a planning framework2 and
effectively communicate to each stakeholder
their scope of responsibilities and interactions
Optimal allocation of
power sector
infrastructure
investments to reliably
meet future load
requirements at the
lowest possible cost
Misaligned planning horizons across
expansion plans and system adequacy reports
NERC to implement existing regulations, align
planning horizons, and develop new guidelines
and a communication mechanism to facilitate an
integrated planning mechanism
Inadequate investment
monitoring and planning
inputs
Power value chain stakeholders lack the
capacity (i.e., technical, software, hardware,
data collection mechanism, etc.) to effectively
carryout planning activities in line with
current rules and leading practices
NERC to develop load forecasting and expansion
plan templates to streamline the review process
and ensure uniformity
More robust and
accurate long-term
expansion plans and the
reduced risk of
misaligned infrastructure
investments
Power value chain stakeholders to improve their
technical capacity to comply with designated
planning responsibilities
Implementation
uncertainty of expansion
plans
Lack of stakeholder incentive arising from
sector liquidity issues, partly attributed to the
recovery costs that must be paid by
consumers for idle/surplus capacities
Provide economic incentives for stakeholders
(e.g., Big Customers, distribution companies, etc.)
to engage in planning activities
Increased stakeholder
buy-in and the availability
of capital expenditure
funds through the Multi-
Year Tariff Order
framework
NERC to develop processes to align planning
requirements with the capital cost allowance in
the Multi-Year Tariff Order framework
2 A USAID-funded consultant under the National Association of Regulatory Utility Commissioners (NARUC) assistance to NERC has developed a system planning
process flow chart.
LONG-TERM PLANNING ASSESSMENT 3
1. INTRODUCTION
1.1 BACKGROUND AND CONTEXT
The Federal Government of Nigeria (FGN) has in place regulations governing the objectives and
procedure for developing power system plans by certain stakeholders across the power sector value
chain. Most of the regulations pertaining to the development of system plans are found in the Nigerian
Electric Power Sector Reform Act 2005 (EPSRA), Market Rules, Grid Code, Distribution Code, and the
Multi-Year Tariff Order (MYTO).
As mandated by EPSRA and described in the Market Rules (Part 5 – Contracts, Generation Adequacy and
Power Procurement during the Transitional Stage), NERC is responsible for reviewing plans submitted by
the operators of the power system to ensure integrated power system development within Nigeria.
However, to date, no power system planning and grid expansion has been fully implemented. Each part of
the power value chain has been planned in isolation, without consideration for the load demand and other
parts of the value chain. In other words, the Nigerian power system has developed without the benefit of
any type of overarching or integrated planning framework.
The lack of planning coordination among the various stakeholders of the power sector value chain has
produced inefficiencies and mismatches in network infrastructure development. The most notable
consequence is capacity bottlenecks limiting the average energy delivered to end users to approximately
4,000 MW3 compared to an available generation capacity of approximately 7,500 MW4. In addition, the
Nigerian power system has surplus capacities that are currently underutilized and will only become
operational when bottlenecks are relieved to meet incident load growth. The sector lacks a logical
framework to prioritize infrastructure investments that will clear bottlenecks and efficiently get over to
where it is ready to be used. Currently surplus capacities are not immediately utilized and are partly
responsible for the liquidity challenges faced by the Nigerian power system. The complete lack of
coordinated planning in the sector has created difficulties in identifying bottlenecks because agencies
planning in silos necessarily tend to have a limited view of the sector. In recent years, this issue has led to
finger pointing and a severe lack of trust among industry participants.
1.2 PURPOSE AND STRUCTURE
The purpose of this sector planning assessment is to explore the state of Nigeria’s power sector planning
apparatus and identify opportunities for improvement. This assessment builds on the USAID funded
technical assistance project by the National Association of Regulatory Utility Commissioners (NARUC)
to develop NERC’s capacity to evaluate system planning, hereinafter referred to as NARUC Technical
Assistance Project (2018).5 The assessment relies on historical references and completed planning
documents.6
The assessment comprises of five parts, providing an overview of the key stakeholders, current
mechanisms, key challenges and impacts, and potential improvements in the following areas:
3 NERC Quarterly Reports 4 NARUC Technical Assistance Project (2018) 5 Project Title: Technical Assistance on Developing the Nigerian Electricity Regulatory Commission’s Capacity to
Evaluate System Planning 6 Note: The Japanese International Cooperation Agency (JICA) is currently conducting a comprehensive Power
Sector Master Plan Study in Nigeria which is expected to include a power demand forecast, a least-cost plan, a
generation plan considering energy supply and best mix, and a transmission development plan based on the
generation plan (https://www.jica.go.jp/nigeria/english/office/topics/150904.html). According to NPSP Meeting Notes
with JICA (September 3, 2018), the JICA Master Plan incorporates the Fichtner study discussed below.
LONG-TERM PLANNING ASSESSMENT 4
1. System Planning: facilitates the coordination, review, and integration of planning activities
across multiple stakeholders within the power sector.
2. Load Demand Forecasting: informs infrastructure investment decisions by improving load
demand forecasts and coordination among power sector stakeholders.
3. Distribution Expansion Planning: aligns the allocation of distribution infrastructure
investments with load demand growth and transmission infrastructure investments.
4. Transmission Expansion Planning: aligns the allocation of transmission infrastructure
investments with load demand growth, distribution infrastructure investments, and generation
resources.
5. Generation Expansion Planning: aligns the allocation of generation infrastructure investments
with energy resource availability and plans, load demand growth, and transmission plans.
This assessment will rely on the Market Rules, along with the Grid Code and Distribution Code, in
reviewing the current mechanisms in place and will only briefly discuss interim provisions in place as they
are subject to intermittent change.7
7 Note: NERC has in place interim provisions that override the load forecast and generation adequacy requirements
of the Market Rules; please refer to Market Rules 21.3 Interim Provisions and the interim provision by NERC titled
Regulations for the Procurement of Generation Capacity 2014.
LONG-TERM PLANNING ASSESSMENT 5
2. SYSTEM PLANNING
2.1 OVERVIEW
The Nigerian power system has developed without the benefit of an overarching or integrated planning
framework, resulting in uncoordinated investments and expansions across the value chain. This is
particularly evident in generation, where unsolicited projects are often taken forward without
consideration of grid capacity or stability. The current model of unsolicited power projects leads to a lack
of control of system design making bottlenecks and underutilized system capacity a likelihood. As this
report shows, it is difficult to adapt to rapidly expanding load growth in a cost-efficient manner without
sector planning and coordination.
The key challenges hindering Nigeria’s system planning mechanism include, but not limited to, the lack of
leadership, an uncoordinated planning framework, power sector stakeholder capacity challenges, and the
lack of stakeholder incentives to commit to long term planning. This provides NPSP with the opportunity
to support the formalization of a planning framework and communication guidelines, in addition to
providing capacity development support and communicating the importance of planning to increase
stakeholder involvement.
Early efforts towards coordinated development of the sector include:
• Electric Power Sector Reform Act 2005 (EPSRA) – Assigns the authority to NERC to set
and enforce standards in the Nigerian power sector, inclusive to assigning NERC with certain
functions to perform in the Nigerian power sector (Part III – Establishment, Functions and Powers
of the Nigerian Electricity Regulatory Commission).
• Market Rules – Establishes an approach to system planning in the Nigerian power system and
allocates planning responsibilities to distribution companies (DISCOs) and the Transmission
Company of Nigeria (TCN). The Market Rules version dated December 2014 was consulted for
this assessment.
• Grid Code – Specifies detailed steps and criteria for planning, particularly for load demand
forecasting, system adequacy studies, and transmission expansion plans. Grid Code Version 03
was consulted for this assessment (August 2018).
• Distribution Code – Outlines requirements for the approach and items DISCOs need to
consider when formulating their distribution expansion plans and load demand forecasts.
Distribution Code Version 02 was consulted for this assessment.
• Multi-Year Tariff Order (MYTO) – Establishes the wholesale and retail tariff over a 15-year
period, subject to periodic reviews, for the Nigerian electricity market. The objective of the
original order (July 2008) is to ensure adequate recovery of investments in the generation,
transmission, and distribution of electricity in Nigeria. The MYTO authorizes NERC with the
responsibility to ensure an adequate recovery of system costs through an efficient tariff
determination while reviewing and approving system plans.
According to these laws and regulations in place by FGN, the system planning process includes multiple
stages involving creation, approval, implementation, and monitoring. The main planning responsibilities
assigned to each stakeholder may be briefly summarized as follows: (1) DISCOs are responsible for
preparing load forecasts and distribution expansion plans; (2) TCN is responsible for preparing national
load forecasts, generation adequacy reports, transmission expansion plans, and generation expansion
plans; and (3) NERC is responsible for coordinating, reviewing, and approving all planning outputs from
stakeholders, in addition to conducting a tariff affordability test to estimate the impact of new power
LONG-TERM PLANNING ASSESSMENT 6
procurements on tariffs.8 Furthermore, NERC engages in monitoring activities to ensure that the
implementation of investments by power sector stakeholders is aligned to the approved plans and is a
function mandated by Part III of the EPSRA.9 A brief overview of this approach is detailed in Figure 1
below.
Figure 110: Nigeria Power System Planning Overview11
As illustrated in Figure 1 above, the key actors in the Nigerian power sector with responsibilities in
planning include NERC, TCN, DISCOs, and Nigerian Bulk Electricity Trading (NBET). Generation
companies (GENCOs) are notably absent, but they are required to provide adequate data to the System
Operator upon request for planning purposes. The Market Rules, along with other FGN laws, do not
mandate GENCOs, gas suppliers, or any other agencies (e.g., the Nigerian Meteorological Agency, the
Nigerian Hydrological Services Agency, etc.) with any forecasting or planning activities.
Despite the existence of the defined process above, in practice, the planning process is not consistent
with current laws and regulations, and global leading practices. The defined process in the figure above
was derived by consolidating the planning guidelines stipulated in the Market Rules, Grid Code, and
Distribution Code. The current laws and regulations do not go as far as clearly defining the interactions
between power sector stakeholders (e.g., how is the planning process initiated and how are stakeholders
informed) and does not align planning horizons for the stakeholders which casts ambiguity on the
frequency of the planning process, refer to the Planning Challenge below.
8 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. 9 EPSRA Part III - Establishment, Functions and Powers of the Nigerian Electricity Regulatory Commission 10 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,
Grid Code Chapter 2 - Planning, and Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures 11 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Figure 1 does not capture all the activities from the Market Rules, Grid Code, and
Distribution Code. Also, the figure does not capture all the interactions between the activities and stakeholders (e.g.,
System Operator involved also in TEP activity). Refer to the relevant subsections below for a more detailed process
description for each stakeholder.
LONG-TERM PLANNING ASSESSMENT 7
In 2018 NERC called for the existing transmission expansion plan from the System Operator (a division
of TCN) and required DISCOs to complete a five-year distribution expansion plan template for review
and approval to ensure an integrated system planning effort.12 An overview of the ongoing planning process
is illustrated in Figure 2 below.
Figure 213: Current System Planning Status as of November 201814
As depicted by the figure above, the ongoing planning process fails to integrate key planning activities such
as DISCO load forecasts between the relevant stakeholders. The significance of not effectively integrating
key planning activities between stakeholders will be further discussed below.
It is important to note the presence of a system planning process flow chart developed by the NARUC
Technical Assistance Project (2018) consultant and NERC. According to the final project report of
NARUC Technical Assistance Project (2018), the system planning process flow chart begins with NERC
requesting load demand forecasts and generation forecasts from load participants and generating
companies, respectively, and ends with the Power Procurement Plan from NBET. The developed flow
diagram accounts for activities such as generation forecasts, generation expansion plans, and stakeholder
engagement. This flow chart is expected to act as a guide for future reviews of system plans within the
Nigerian power sector.
2.2 KEY CHALLENGES AND IMPACTS
2.2.1 Planning Challenge
FGN rules and regulations do not lay out a clear process or communication mechanism between power
sector stakeholders for system planning in line with an effective integrated sector master planning
framework.
This causes confusion over the scope of responsibilities, interactions with other stakeholders, where to
send the output of planning activities, and how to implement respective plans. The lack of clear guidelines
or procedures have consequences in three key areas: (1) communication and document submission; (2)
accounting for future domestic load and contracted power export requirements; and (3) implementing an
effective resource plan.
12 NARUC Technical Assistance Project (2018). 13 Ibid. 14 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Furthermore, Fichtner was consulted for the preparation of the most current TEP.
LONG-TERM PLANNING ASSESSMENT 8
Another contributing factor may be the misaligned planning horizons across the Nigerian power sector
value chain, refer to Table 2 below.
Table 2: Planning horizons
Document Planning Horizon Reference
Distribution
Expansion Plan /
Load Demand
Forecast
5 years
Distribution Code (Part 2) 2.1.3 Distribution Planning
Responsibility and Distribution Code (Part 2) 2.3.1 Load
Forecast
Transmission
Expansion Plan /
Load Demand
Forecast
20 years Grid Code 6.2.1 Long-term Demand Forecast and Grid
Code 7.2.7 Long-term Expansion Plan
TCN System
Adequacy
Reports
(Generation,
Transmission,
etc.) /
Load Demand
Forecast
10 years
Market Rules 21.1.1 Annual Load Projections Report and
Market Rules 21.2.2 Generation Adequacy Report; TCN
System Adequacy Reports (2017)
2.2.2 NERC Capacity Challenge
Despite the guidelines in place regarding system planning, NERC suffers technical and resource constraints
that inhibit the achievement of system planning objectives. NERC does not have adequate technical
capacity to perform tasks such as effectively reviewing system plans and/or effectively performing a tariff
affordability test. Furthermore, it has insufficient resources to effectively monitor all procurements or
investments in the power sector. However, it is important to note that NARUC is providing technical
assistance to NERC for the development of a Review, Approval, and Monitoring Guide for reviewing,
approving, and monitoring system development plans. The technical assistance has provided NERC with
the following two mechanisms: (1) a framework for monitoring procurement and investment in the power
sector; and (2) review and approval procedures and templates for system planning.15
15 NARUC Technical Assistance Project (2018).
NPSP can support NERC and TCN in (1) implementing an appropriate energy
resource planning framework; (2) organizing an industry workshop with all system
participants to effectively communicate the steps towards effective planning; and (3)
developing the necessary regulatory guidelines required to support an energy
resource planning framework. In addition, NPSP can develop a communication
mechanism between power sector stakeholders and train stakeholder personnel on
the requirements and guidelines for interacting with other entities in the power
sector.
LONG-TERM PLANNING ASSESSMENT 9
2.2.3 Sector Liquidity and Stakeholder Incentive Challenge
Stakeholders of the power value chain lack a compelling driver to implement the current guidelines set in
place by FGN regulations and effectively engage in long-term planning activities. The lack of a cost-
reflective tariff, active Power Purchase Agreements (PPAs)/ Gas Supply Agreements, financing options,
and reliable payments may hinder the required efforts from stakeholders to implement long-term
expansion plans or even maintain their existing capacity. For example, DISCOs may be reluctant to
develop and adhere to a Performance Improvement Plan if the commission is unable to commit to tariff
revisions. It is worth noting that investments in the power sector rely on tariffs for assurances and cost
recovery.
2.2.4 Stakeholder Capacity Challenge
In the current system there are numerous instances of planning and study methodologies failing to comply
with requirements mandated by FGN laws and regulations. An effective system planning mechanism relies
on accurate and comprehensive inputs from other power sector entities, such as accurate forecasts of
load demand. It is crucial that any analysis carried out, which generates inputs for subsequent activities, is
compliant with FGN rules and leading practices to ensure accuracy and, most importantly, consistency
across released reports, especially with respect to load forecasts and system studies. A major contributing
factor to this discrepancy is likely the capacity gap facing power sector stakeholders with planning-related
responsibilities, including TCN, DISCOs, and large consumers (e.g., industrial companies).
2.2.5 Power System Optimization Impact
A lack of adherence to a system planning approach has led to inadequate allocation of power sector
infrastructure resources (e.g., generating units, transmission lines). The sector needs an integrated plan to
maximize infrastructure investments by identifying priority projects and geographic locations. The current
model of unsolicited power projects leads to a lack of control of system design making it difficult to adapt
to serve future load growth. There is no shared and consistent load projection estimate among the key
NPSP can provide technical assistance to NERC in: (1) acquiring and implementing
software tools for use in long term planning; (2) updating and operationalizing the
Review, Approval, and Monitoring guide provided through the NARUC Technical
Assistance Project (2018), and (3) implementing a NERC capability development
program.
NPSP can support the (1) communication of the importance of accurate data on the
power sector asset base for tariff determination; (2) audit and verification of power
sector infrastructure assets; and the (3) implementation of an asset register to ensure
the presence of accurate asset data for the process of tariff determination. In
addition, NPSP will work with NERC to identify and address governance issues.
To address the Stakeholder Capacity Challenge, NPSP can support the following: (1)
development of forecasting and expansion plan templates; (2) formation of
operational plans to address capacity gaps (e.g., hardware, software, etc.) afflicting
stakeholders; and (3) implementation of stakeholder development programs.
LONG-TERM PLANNING ASSESSMENT 10
actors in the Nigerian power sector. In order for the system to work, planning has to consider project
impacts on all parts of the value chain over the long run.
The absence of a coordinated planning mechanism has led to redundant and surplus capacities, creating
bottlenecks in the grid system, and placing infrastructure where there is limited load (and vice versa). As
a result, electricity consumption averages around 4,000 MW for an estimated national load demand
estimated to be as high as 11,000 MW.16
Figure 3 below offers an approximation of the current idle capacity, under the condition of no technical
or operational losses, from the geographic misplacement of infrastructure resources and unsolicited
power projects arising from absent integrated system planning mechanisms.
Figure 317: Approximation of Current Idle Infrastructure Capacity18
2.2.6 Value Chain Liquidity Impact
System Affordability – As noted and illustrated in the figure above, the presence of surplus capacities
has an adverse effect on system affordability. More specifically, surplus capacities have an adverse effect
on system affordability if they are considered as part of the asset base during tariff determination. In other
words, rate payers will be unfairly burdened if idle capacities are inadvertently included in the asset base.
Hence, the regulator should effectively distinguish between idle and utilized portions of power sector
assets and only account for utilized portions in the asset base during tariff determination.
Furthermore, system affordability may be adversely impacted if all PPAs signed by NBET are fully activated
because an activated PPA requires payment be made for available capacity regardless of whether or not
energy is delivered. Only five GENCOs currently receive payment for available capacity, three of which
have active gas supply agreements whereas the other two have a minimum guaranteed capacity payment.
The remaining GENCOs receive payments based on energy delivered.
16 NARUC Technical Assistance Project (2018), Transmission Expansion Plan (Fichtner), NERC Quarterly Reports,
and Year 1 NPSP Workplan (USAID). 17 NERC Quarterly Reports, NARUC Technical Assistance Project (2018), Transmission Expansion Plan (Fichtner),
and Year 1 NPSP Workplan (USAID). 18 Note: The installed capacity numbers in Figure 3 are estimates.
LONG-TERM PLANNING ASSESSMENT 11
Efficient Tariff Determination – The lack of an integrated approach in reviewing and approving system
plans hinders the adequate recovery of system costs through an efficient tariff determination. In reference
to Market Rules 21.1.1 – Annual Load Projections Report, NERC is responsible for performing a tariff
affordability test to estimate the impact of new power procurements on tariffs. The absence of a cost-
reflective tariff is a key liquidity challenge in the Nigerian electricity market.
Costs Benefit Analysis – A long term system plan, with broad stakeholder participation, can ensure the
selection of the lowest cost and lowest risk investment plan in developing a policy based efficient power
sector. Conversely, the absence of a plan can lead to the pursuit of high cost and high-risk investment
plans, resulting in additional deadweight infrastructure in the sector. Deadweight infrastructure refers to
investments which add to the running costs of the power sector despite having only a negligible impact
on the overall service delivery.
2.2.7 Investment Monitoring Mechanism Impact
Without monitoring by NERC, there is no way to ensure that the implementation of investments is aligned
with approved expansion plans. Misaligned investments may result in an overinvestment or an
underinvestment in distribution grids that: (1) do not demand any further loads or are unwilling to pay for
additional electricity supply; or (2) in grids that demand further loads or are willing to pay for additional
electricity supply, respectively. Recent reports have demonstrated the presence of capacity mismatches,
especially between transmission and distribution networks.19 In other words, assuming approved
expansion plans have taken into consideration a cost-benefit analysis, monitoring ensures investments are
aligned to achieving a positive return on investments, thereby reducing liquidity risk.
2.2.8 Social and Environmental Impact
The lack of a sector plan, along with lax monitoring mechanisms, makes it difficult to assess the social and
environmental impacts of power sector infrastructure investments. In other words, a long-term plan can
help ensure power sector infrastructure investments meet social and environmental objectives set by
FGN.
19 NARUC Technical Assistance Project (2018)
LONG-TERM PLANNING ASSESSMENT 12
3. LOAD DEMAND FORECASTING
3.1 OVERVIEW
There is no shared and consistent load projection estimate and approach among the key actors in the
Nigerian power sector. Load demand projections are a key input of power sector expansion plans. An
inaccurate load projection may result in an inadequate allocation of power sector resources which fails to
meet future load demand and results in unnecessary system costs through the presence of idle resources.
It is worth noting that given the current model of unsolicited power projects, load demand forecasts don’t
seem to play a crucial role in informing infrastructure investments.
The main challenge hindering Nigeria’s load demand forecasting mechanism is the lack of stakeholder
technical capacity. This provides NPSP with the opportunity to support NERC, TCN, DISCOs, and large
users with the development of load forecast templates and operational plans to address technical capacity
gaps.
The Grid Code and Distribution Code contain rules and regulations that govern the process of load
demand forecasting. A review of the TCN System Adequacy Report (2017) and the TCN Demand
Forecast Report (2017) reveals an independent load projection by TCN (forecasted by the Japan
International Cooperation Agency) without taking into consideration any input from DISCO load demand
forecasts.20 This current practice is not compliant with Grid Code 6.2.2 Long-term Demand Forecast and
the Market Rules. Like TCN, DISCOs use load projections without required reviews and approvals laid
out in the Market Rules.21 Figure 4 below illustrates the missing procedural steps required by the Market
Rules, Grid Code, and Distribution Code.
Figure 422: Load Forecast Process Gaps23
3.1.1 Grid Code
Grid Code 6.2 Long-term Demand Forecast specifies that a new 20-year demand forecast should be
published every three years, with annual updates, and identifies the factors that need to be taken into
20 TCN System Adequacy Report (2017) and TCN Demand Forecast Report (2017) 21 NARUC Technical Assistance Project (2018) 22 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,
Grid Code Chapter 2 - Planning, Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures,
and NARUC Technical Assistance Project (2018) 23 Note: TCN is currently the System Operator of the Nigerian power sector. Figure 4 does not capture all the
activities from Market Rules and other FGN laws and regulations such as the Grid Code and Distribution Code.
LONG-TERM PLANNING ASSESSMENT 13
consideration when generating demand forecasts, respectively. This assessment does not seek to list all
existent procedural rules or identify all the procedural gaps with FGN rules. However, a cursory review
of TCN’s Demand Forecast Report (2017) yields a brief assessment on compliance gaps with the Grid
Code; please refer to Table 3 below.
Table 324: Current TCN Forecast Factors vs. Grid Code Forecast Factors25
The load demand forecast used in TCN’s system adequacy assessment is developed by JICA. JICA
forecasted both energy and peak demand on a nationwide and regional basis for the period of 2017 to
2027. In developing each forecast, JICA utilized three (low, average, and high) GDP growth scenarios. It
is worth noting that the transmission expansion plan drafted by Fichtner in December 2017 (refer to the
Transmission Expansion Planning Section), calculated a revised demand forecast using data from previous
JICA progress reports. More specifically, the transmission expansion plan by Fichtner consulted the
following previous demand forecasts in its own demand forecast calculation: 1) the 2015 JICA demand
forecast, 2) the 2012 TCN demand forecast, and 3) the 2009 Tractebel demand forecast.26
3.1.2 Distribution Code
Section 2.3 in Part 2 of the Distribution Code specifies that a 5-year demand forecast should be published
annually and identifies the factors (i.e., growth in population, energy sales per customer category, etc.)
which need to be taken into consideration when generating demand forecasts.27 DISCOs have not been
preparing these forecasts on an annual basis. Although this assessment does not seek to list all existent
procedural rules or identify all the procedural gaps with FGN rules, the table below yields a cursory
assessment of the load demand forecast approach submitted by each DISCO. Table 4 below illustrates
that DISCOs, for the majority, have no consistent formal approach to forecasting load demand.
24 TCN Demand Forecast Report (2017) and Grid Code 6.2.2 and 6.2.3 - Long-term Demand Forecast 25 Note: Table 3 above is meant to illustrate a discrepancy between current practices and regulations. It is not meant
to critique or offer an analysis on the robustness of the TCN report load demand forecast approach by JICA. If there
was a slight overlap with what was covered in the report and what is required from the Grid Code, it was marked
as present. 26 Transmission Expansion Plan (Fichtner) 27 Section 2.3 in Part 2 of the Distribution Code – Load Forecast
LONG-TERM PLANNING ASSESSMENT 14
Table 428: Current DISCO Forecast Approach29
3.2 KEY CHALLENGES AND IMPACTS
3.2.1 Power Exports Challenge
Most export requirements are agreement-based (i.e., the power requirements are fixed). Nonetheless, it
is crucial for NERC and the System Operator, TCN, to account for future potential export requirements
when ensuring future system reliability through long-term planning. Currently NERC has not received any
load forecasts or potential future requirements from any entity receiving exports as part of its current
review of load forecasts and expansion plans.
As a member of the West African Power Pool, Nigeria currently exports approximately 350 MW of
power to utilities in neighboring countries.30 Benin/Togo and Niger account for approximately 250 MW
and 100 MW of Nigerian exported power, respectively.31 Nigeria’s current export requirement accounts
for approximately nine percent of the power distributed to end users (approximately 4,000 MW).32
28 NARUC Technical Assistance Project (2018) 29 NARUC Technical Assistance Project (2018) carried out the analysis using completed submissions by DISCOs of
the general template provided by NERC. 30 TCN 31 Ibid 32 NERC Quarterly Reports
LONG-TERM PLANNING ASSESSMENT 15
3.2.2 Accurate Load Forecasts Challenge
Limited technical capacity, along with ineffective data collection and database management systems at
DISCOs are a contributing factor to inaccurate forecast estimates. The lack of a scalable software or
formal shared model template to be used at DISCOs for forecasting can hinder accuracy and most of all
make the review process more difficult for the commission.
It is important to note that large users, such as industrial customers, also have a role in providing accurate
forecasts. According to Section 2.3.4 in Part 2 of the Distribution Code, large users should provide
DISCOs with their 5-year energy demand forecasts on an annual basis.33
33 Section 2.3 in Part 2 of the Distribution Code – Load Forecast
NPSP can help TCN and NERC develop commercial frameworks around the
purchase of power by utilities in West African countries. NPSP can support the
inclusion of export demands in long-term planning and the development of PPAs
between Nigerian GENCOs and West African utilities.
To improve load forecast accuracy, NPSP can provide support to the following
power sector stakeholders:
1. NERC: NPSP can support the development of load forecast templates and
methodology guidelines, in addition to supporting the improvement of load
forecast review mechanisms.
2. DISCOs and users with large connections (e.g., industrial companies): NPSP
can address capacity gaps by implementing stakeholder development
programs.
3. TCN: NPSP can support with load forecast data retrieval, analysis,
processing, and incorporating the processed data into scheduling and
dispatch functions.
LONG-TERM PLANNING ASSESSMENT 16
4. DISTRIBUTION EXPANSION PLANNING
4.1 OVERVIEW
Until now, distribution expansion was carried out in isolation by the DISCOs and without the presence
of robust and approved distribution expansion plans. Carrying out distribution expansion investments in
isolation from the power sector value chain has resulted in the placement of distribution capacity
infrastructure that remains idle for prolonged periods of time due to not accounting for the future
availability of generation resources and transmission capacity at certain connection points. This previous
practice is not compliant with the Market Rules and leading practices. It is worth noting that currently
NERC received five-year distribution expansion plan templates from DISCOs for review, along with
associated investment plans and single line drawings.
The main challenge hindering Nigeria’s distribution expansion planning mechanism is the limited technical
capacity of DISCOs. This provides NPSP with the opportunity to support DISCOs with the development
and implementation of operational plans to address technical capacity gaps.
Figure 5 below illustrates the procedural steps required by the Market Rules with respect to distribution
system planning. Activities deemed to be critical for an integrated approach to planning are highlighted.
Figure 534: Distribution Expansion Plan Market Rules Process35
Given that the Market Rules are written in the context of the transitional and medium-term stages of
NESI, the activities of NBET are not highlighted as critical integration activities. NBET is best described as
an intermediary between GENCOs and DISCOs in the process of power procurement. NBET engages in
34 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,
Grid Code Chapter 2 - Planning, and Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures 35 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Figure 5 does not capture all the activities from Market Rules and other FGN laws and
regulations such as the Distribution Code.
LONG-TERM PLANNING ASSESSMENT 17
active trading of bulk power as a buyer of power from GENCOs and a seller of purchased power to
DISCOs.
4.1.1 Distribution Code
Another FGN law and/or regulation governing the process and requirements of the Distribution
Expansion plan is the Distribution Code. The specific rules that govern the requirements and approach to
DISCO expansion planning are in Section 2 under Part 2 of the Distribution Code. Other than their
current NERC submission, DISCOs have not been preparing expansion plans on a periodic basis. Although
this assessment does not seek to list all existent procedural rules or identify all the procedural gaps with
FGN rules, a cursory review of the NARUC Technical Assistance Project (2018) inception report analysis
yields a brief assessment on compliance gaps with the Distribution Code; please refer to Table 5 below.
Table 536: DISCO Expansion Plan vs. Required Distribution Code Attributes37
Most DISCOs do not seem to be engaging in any form of formal study or analysis in formulating their
expansion plan. Furthermore, projected investment costs supplied by the DISCOs were mostly not
supported by the required planning and system studies. As a reminder, it is prudent to note that most
36 NARUC Technical Assistance Project (2018) and Section 2 in Part 2 of the Distribution Code – Distribution
Planning Procedures (2.1.3, 2.4, and 2.5) 37 Note: Table 5 illustrates a discrepancy between current practices and regulations. It is not meant to critique or
offer an analysis on the robustness of the approach for each DISCO. Also, the required demand forecast portion of
expansion plans is covered in the Load Demand Forecasting subsection above. If there was a slight overlap with what
was covered in the report and what is required from the Distribution Code, it was marked as present.
LONG-TERM PLANNING ASSESSMENT 18
expansion plans require accurate load forecasts; refer to the Load Demand Forecasting section above for
a brief discussion on the current state of DISCO load demand forecasting.
Table 6 below offers more detail on the Distribution Code (Part 2) sections that govern the planning
process and requirements of DISCOs in formulating expansion plans.
Table 6: Distribution Code (Part 2) Sections Governing DISCO Planning
Section Activity Required Components
2.1.3
Annual 5-year
Distribution
Plan
projections
1. Energy and demand forecasts
2. Distribution feeder routing and sizing
3. Distribution reactive power compensation plan
4. Distribution losses reduction plan
5. Other distribution reinforcement plans
6. A technical and economic analysis to justify the 5-year distribution expansion
plan
2.4
Planning
process studies
and analysis
objectives
1. Evaluate the requirement of distribution system reinforcement projects
2. Identify corrective measures to eliminate the deficiencies in the system
3. Assess the impact on the system due to the load forecast or any proposed
equipment change
4. Determine optimum patterns for feeder development taking into account
existing or future substations
5. Develop optimum reactive power compensation programs
6. Develop an optimum feeder configuration and switching controls
7. Determine the cost effectiveness of loss reduction measures without
compromising security standards
2.5 Studies and
analysis
1. Voltage drop studies
2. Short circuit studies
3. Three-phase short-circuit studies
4. System losses studies
5. Distribution reliability studies
4.2 KEY CHALLENGES AND IMPACTS
4.2.1 Network Expansion Challenge
DISCOs lack the necessary capital expenditure funds to expand their networks because of the difficulty
to secure financing, the lack of a cost reflective tariff, and the possible inadequate capital expenditure
allocations in recent MYTO adjustments. As a result, the feasibility of implementing any type of distribution
expansion plan is low.
4.2.2 DISCO Capacity Challenge
The infrequent formulation of distribution expansion plans utilizing methodologies set by FGN rules and
leading practices may be attributed to the DISCO’s current capacity and technical capabilities. DISCOs
lack any effective data collection methods, database management systems, software, and formal shared
model templates to adequately conduct the required studies and analysis necessary in forming expansion
plans.
LONG-TERM PLANNING ASSESSMENT 19
4.2.3 Power Procurement and Distribution Expansion Impact
Not taking into consideration the current and future state of generation adequacy, along with integrated
transmission and generation capacity plans, results in inadequate distribution expansion investments. In
other words, not accounting for the future availability of generation resources to supply demanded loads
can result in the placement of distribution capacity infrastructure that remains idle for prolonged periods
of time.
To improve distribution expansion, NPSP can support DISCOs to address capacity
gaps and improve their ability to conduct effective distribution expansion planning.
LONG-TERM PLANNING ASSESSMENT 20
5. TRANSMISSION EXPANSION PLANNING
5.1 OVERVIEW
One of the main purposes of the Transmission Expansion Plan is to ensure future load and generation
connections can be handled by the transmission system. If not, then TCN is responsible for identifying and
planning for required expansions. Until recently, Transmission Expansion plans were carried out in
isolation from the power sector value chain. In combination with other factors, this has contributed to an
inadequate transmission evacuation capacity of approximately 7,000 MW, despite an installed transmission
transformation capacity of approximately 11,000 MW, that fails to meet the national load demand
(approximately 11,000 MW) and available output from GENCOs (approximately 7,500 MW).38 This
previous practice is not compliant with the Market Rules and leading practices.
The main challenge hindering Nigeria’s transmission expansion planning mechanism is the limited technical
capacity of TCN. This provides NPSP with the opportunity to support TCN with the development and
implementation of operational plans to address technical capacity gaps.39
Figure 6 below illustrates the procedural steps required by the Market Rules with respect to transmission
system planning. Activities deemed to be critical for an integrated approach to planning are highlighted.
Figure 640: Transmission Expansion Plan Process41
It is worth noting that TCN, in conflict with FGN rules and regulations, does not release technical reports
on electricity system adequacy annually, which are required inputs to formulating the Transmission
38 NARUC Technical Assistance Project (2018) and Year 1 NPSP Workplan (USAID) 39 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. 40 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and
Grid Code Chapter 2 - Planning 41 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Figure 6 does not capture all the activities from Market Rules and other FGN laws and
regulations such as the Grid Code.
LONG-TERM PLANNING ASSESSMENT 21
Expansion Plan. Table 7 below offers a brief overview of the current approach and methodologies utilized
for the relevant system adequacy reports.
Table 7: System Adequacy Reports Current Methodology Overview42
Part Report Objective / Metric Performance Indices / Methodology
Inputs
One
Generation
Adequacy Report -
Retrospective
(2015)
Analyzes the capability of
generating stations to supply
load and provide the
required ancillary services
• Generation capacity before constraints
• Energy not supplied
• Utilization of electrical energy
• Remaining capacity margin
• Frequency regulation
• Voltage regulation (Currently unknown data)
• Black start capability
• System collapses
Two
Transmission
Adequacy Report -
Retrospective
(2015)
Analyzes the capability of the
transmission system to
transmit power reliably from
GENCOs to DISCOs
• Transmission line reliability (failure rate,
outage frequency, interruption duration,
etc.)
• Transformer reliability (failure rate,
availability, and average interruption
duration)
• Transmission constraints
• Voltage regulation
• Loss of transmission system
• Load management
Three Demand Forecast
Report Please refer to the Load Demand Forecasting section above
Four
Generation
Adequacy Outlook
(2017 – 2027)
Analyzes generation
adequacy (10yr outlook)
through energy and capacity
margins under different
scenarios (e.g., low, base, and
high case)
• Demand forecast
• Planned generation expansion
• Technical availability of power plants
• Constraints of primary energy (gas and
water)
Five
Transmission
Adequacy Outlook
(2017 – 2027)
Analyzes transmission
adequacy (10yr outlook)
using DC model of power
system, in addition to
determining 330kv and 132kv
networks separately
• Ongoing transmission projects
• Ongoing generation projects
• Transmission information (topology, thermal
capability, etc.)
• Maximum short-circuit levels
Currently, the NPSP team is aware of only one recent Transmission Expansion Plan, the December 2017
plan drafted by Fichtner. The Transmission Expansion Plan (Fichtner) covers the period 2020 to 2037
using TCN’s annual technical reports, up to the year 2015, as its main input. Figure 7 below offers a brief
overview of the components and approach adopted in the plan.
42 TCN System Adequacy Reports (2017)
LONG-TERM PLANNING ASSESSMENT 22
Figure 7: Transmission Expansion Plan (Fichtner) Overview43
5.1.1 Grid Code
The specific rules that govern the requirements and approach to transmission expansion planning are in
Grid Code Chapter 2 Planning.
Grid Code Section 7 Expansion Planning discusses the timelines, user involvement, analysis, components,
and process of the transmission expansion planning approach. It is worth noting that TCN has not been
preparing expansion plans on a periodic basis in accordance to the stipulated regulations. More specifically,
Section 7.2 of the Grid Code clearly lists out the required process and components/analysis for drafting
the long-term expansion plan report. Grid Code Section 7.2.4 mandates the Transmission Service Provider
with the responsibility to identify expansion alternatives, with input from relevant stakeholders, that
address the combination of: (1) long-term demand forecasts; (2) refurbishment needs; and (3) current
transmission performance. As per Grid Code Section 7.2.5 the evaluation of alternatives should be
performed by taking into consideration the following studies: (1) a load flow analysis; (2) fault level
calculations; (3) stability studies; (4) reliability studies; and (5) a financial analysis.
Grid Code Section 7.2.7 Long-term Expansion Plan Report defines the following sections that need to be
included in the long-term expansion plan report:
1. Long-term demand forecast;
2. Long-term generation adequacy forecast;
3. Long-term transmission adequacy forecast;
4. Long-term zonal supply and demand margin;
5. Long-term statutory outage plan for transmission infrastructure;
6. Long-term refurbishment plan;
7. Alternatives (identification and analysis);
8. Capital investment program; and
9. Financial motivation.
In addition, Sections 7.3 and 8 of the Grid Code pertain to guidelines for user involvement and the data
requirements for long-term planning, respectively. More specifically Section 8 along with Appendix 5
through Appendix 7 clearly list out all the user information, DISCO and GENCO, required.
43 Transmission Expansion Plan (Fichtner)
LONG-TERM PLANNING ASSESSMENT 23
Figure 8 below illustrates an overview of the required Grid Code process in generating Transmission
Expansion Plans. Activities deemed to be critical for an integrated approach to planning are highlighted.
Figure 844: Transmission Expansion Plan Grid Code Process45
5.2 KEY CHALLENGES AND IMPACTS
5.2.1 TCN Capacity Challenge
In line with the Stakeholder Capacity Challenge raised in the System Planning section, the infrequent
submission and/or revision of expansion plans, along with system adequacy reports, utilizing
methodologies set by FGN rules (e.g., Market Rules 21.2 Generation Adequacy Report, Grid Code 7.2
Long-term Expansion Plan, etc.) and leading practices may be attributed to TCN’s current capacity and
technical capabilities. Relative to the other stakeholders of the power section value chain, TCN has human
resources that are technically capable and has software tools that are implemented. However, TCN’s
capacity is constrained by an inadequate information management system, inadequate workflow processes,
and their reliance on receiving accurate inputs from DISCOs and GENCOs.
5.2.2 Transmission Expansion Impact
The lack of an integrated approach to planning, inclusive to estimating load forecasts without DISCO
inputs, has led to the misalignment of transmission capacity with generation resources and load
requirements at certain connections. Current transmission evacuation capacity (approximately 7,000
MW) is less than the national load demand (approximately 11,000 MW) and available output from
GENCOs (approximately 7,500 MW), even though the installed transmission transformation capacity is
11,000 MW.46
44 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and
Grid Code Chapter 2 - Planning 45 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Figure 8 does not capture all the activities from Market Rules and other FGN laws and
regulations such as the Grid Code. 46 NARUC Technical Assistance Project (2018), NERC Quarterly Reports, Transmission Expansion Plan (Fichtner),
and Year 1 NPSP Workplan (USAID)
LONG-TERM PLANNING ASSESSMENT 24
6. GENERATION EXPANSION PLANNING
6.1 OVERVIEW
Investments in generation infrastructure are carried out with no generation expansion plan and in isolation
from any inputs from other stakeholders of the Nigerian power sector. The absence of a generation
expansion plan along with any present explicit mechanism for generation expansion planning, implies no
previous energy resource plan (e.g., gas transmission expansion plans) integrated with decisions on
generation investments. Unsolicited generation projects are often taken forward for FGN approval
without consideration of grid capacity and energy resource availability. This is clearly depicted by an
available generation capacity of approximately 7,500 MW, despite an installed gross power generation
capacity of 13,500 MW.47
The main challenge hindering Nigeria’s generation expansion planning mechanism is the lack of an adequate
mechanism for generation expansion planning and GENCO feedback. This provides NPSP with the
opportunity to support the development of a mechanism for the formation of a robust generation
expansion plan that is effectively communicated to GENCOs and considers energy resource availability
and inputs from relevant stakeholders.
Generation Expansion Planning helps to:
1. Ensure the presence of enough generation capacity to efficiently supply current and future
load demand;
2. Ensure system reliability with the presence of reserve generation capacity; and
3. Properly anticipate and address maintenance needs, outage occurrences, development needs
(financing, licenses, etc.), and energy resource supply needs such as the availability and/or price
of gas, coal, or water.
Currently, this assessment is aware of only one recent completed generation expansion plan.48 TCN, along
with Fichtner, in 2017 identified a generation development plan for consideration in the formulation of
the Transmission Expansion Plan and network calculations. The plan is referenced to be in Annex 6.1 of
the Transmission Expansion Plan (Fichtner).
According to the Transmission Expansion Plan (Fichtner), Annex 6.1 identifies a generation setup for the
modernization of generating units, implementation of new generating units at existing sites, and
implementation of complete new power plants with the aim to supply potential load demand. The
generation plan has been finalized and revised by TCN at the end of August 2017 considering existing
plants and plant candidates. To bolster the proposition of building certain types of plants at certain sites,
TCN initiated the development of a gas transmission system expansion plan as well. The expansion plan
proposes new gas transmission pipelines to supply the northern and central regions of Nigeria. Figure 9
below is a schematic from TCN, retrieved from the Transmission Expansion Plan (Fichtner), showing the
proposed and ongoing gas transmission expansion plan with some locations for proposed new gas fired
power plants.
47 NARUC Technical Assistance Project (2018) and Year 1 NPSP Workplan (USAID) 48 As noted earlier, JICA is currently in the process of conducting a comprehensive power sector Master Plan which
includes an optimal power generation master plan considering constraints in energy supply. Also, it is worth noting
that according to NPSP meeting notes with JICA (September 3, 2018), the JICA plan incorporates the Fichtner plan.
LONG-TERM PLANNING ASSESSMENT 25
Figure 9: Existing and Proposed Gas Transmission Infrastructure49
It is worth noting that a comment in the Transmission Expansion Plan (Fichtner) stated that the generation
plan in Annex 6.1 has made rather optimistic assumptions with respect to the implementation of candidate
power plant projects.
Furthermore, the generation plan proposed in Annex 6.1 of the Transmission Expansion Plan (Fichtner)
has not been subject to a thorough generation adequacy and feasibility assessment. The only present
generation adequacy report this assessment is aware of is the TCN Generation Adequacy Report: Outlook for
2017 – 2027. Although there is a present generation adequacy report, by the time the report was
prepared there was no Generation Expansion Plan available. As a result, the report only considered
planned power projects.
None of FGN laws and regulations clearly specify any criteria or processes to be undertaken in the
formulation of a generation system plan, along with an energy resource plan. The System Operator is
mandated to undertake system planning for generation; Market Rules 9.1.2 System Operation. However,
the Market Rules only go as far as mandating the System Operator with the responsibility to select the
locations for new generation capacity; Market Rules 21.1.6 Annual Load Projections Report. Figure 10
below illustrates the procedural steps required by the Market Rules with respect to generation location
selection and new power procurement. Activities deemed to be critical for an integrated approach are
highlighted.
49 Transmission Expansion Plan (Fichtner)
LONG-TERM PLANNING ASSESSMENT 26
Figure 1050: Generation Expansion Plan Process51
As illustrated by the figure above, the System Operator is mandated with reviewing the Transmission
Expansion Plan, taking into consideration reserve requirements, and identifying the best location for
additional generation; Market Rules 21.1.6 Annual Load Projections Report. Although not stated above,
the output of the load demand and generation plan is reported in the Load Projection Report. According
to Market Rule 21.2.1 Generation Adequacy Report, after the plan is formulated, the Market Operator is
mandated in evaluating the adequacy of the generation plan by preparing the Generation Adequacy Report.
Afterwards, based on the Generation Adequacy Report, NERC will decide on the quantity to be traded
in new contracts and will notify NBET of the quantity authorized for new power procurement by each
DISCO. NBET then procures the required additional capacity on behalf of the DISCOs, but with their
consent on the final terms of the PPAs.
It is crucial to note that a Generation Adequacy Report is not a substitute for a Generation Expansion
Plan. Furthermore, as noted above, the generation adequacy outlook report published by TCN is not
relevant since it should be testing the adequacy of a proposed generation plan to ensure the plan satisfies
forecasted load demand reliably.
In addition, there is no identified planning mechanism to ensure generation plans, inclusive to energy
resource plans, receive the relevant inputs from gas suppliers, the Nigerian Meteorological Agency, and
the Nigeria Hydrological Services Agency.
50 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and
Grid Code Chapter 2 - Planning 51 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the
Nigerian power sector. Figure 10 does not capture all the activities from Market Rules and other FGN laws and
regulations such as the Grid Code.
LONG-TERM PLANNING ASSESSMENT 27
6.1.1 Interim Provision
As mentioned in the System Planning subsection above, NERC has in place an interim provision that
overrides the requirements on the preparation of the Load Projection Report; Market Rules 21.1.7 Annual
Load Projections Report. The current interim provision, titled Regulations for the Procurement of Generation
Capacity 2014, sets a standard in which the System Operator, in lieu of the Load Projection Report, will
only prepare an annual report assessing system capacity needs and constraints for a five-year period ahead.
The interim report lists out, but not limited to, the following components to be considered in the 5-year
report: (1) projected demand; (2) recommended injection points for generation capacity; (3) current and
projected natural gas and other fuel supply capabilities; and (4) projected transmission grid system
capabilities. The interim provision goes on to stipulate guidelines on the process of solicitation and
procurement for new generation capacity.
6.2 KEY CHALLENGES AND IMPACTS
6.2.1 Guideline and Coordination Challenge
Although Market Rules 9.1.2 System Operation assigns the responsibility of generation system planning to
the System Operator, it falls short in providing details on how to conduct the planning exercise and which
stakeholders to coordinate with. Furthermore, the Grid Code does not describe any responsibility or
process with respect to generation system planning assigned to the System Operator.
6.2.2 Generation Expansion Planning Challenge
Current and potential plant developments disclosed by GENCOs and power system users are taken into
consideration when planning for generation capacity expansion. However, a challenge lies in whether to
fully account for the MW produced by generation projects. A generation developer needs to reach various
agreements with FGN (e.g., PPAs) and regulatory entities such as NERC (e.g., license acquisitions) to
implement their generation projects. The process of reaching agreements and obtaining licenses may delay
the start date to which the potential project may provide available generation capacity. It may even lead
to the cancellation of projects or the development of plants that sit idle. Also, there are uncertainties with
respect to the implementation of the generation expansion program due to the large investment
requirements and financing needs. The rehabilitation and replacement of selected existing generation
capacity in the expansion plan will also require large investments. It is important to note that non-payment
for generation capacity delivered or made available creates a disincentive for GENCOs to maintain existing
capacity and/or increase capacity through plant refurbishments.
6.2.3 GENCO Feedback Mechanism Challenge
A major component of generation planning is the feedback mechanism used by System Operators to
communicate to GENCOs for the supply of future capacity at certain locations. Although the current
Transmission Expansion Plan (Fichtner) has a Generation Expansion Plan located in Annex 6.1, there is no
clear feedback mechanism to GENCOs or power sector users in the installation or modification of
generating units at certain locations. The assessment noted a possible feedback mechanism stipulated in
Grid Code Section 7.3.3 Plant Modification, however it should be subject to more clarification.
Building on the response to the Planning Challenge above, NPSP can develop a
mechanism to ensure both generation and energy resource plans receive the relevant
inputs from gas suppliers, the Nigerian Meteorological Agency, and the Nigeria
Hydrological Services Agency.
LONG-TERM PLANNING ASSESSMENT 28
6.2.4 Energy Resource Planning Challenge
Although the presence of an energy resource plan can help ensure fuel supply for power generation, it is
subject to external constraints beyond the control of planning. Like the Generation Expansion Planning
Challenge noted above, the feasibility of implementing the energy resource plan is low because of the large
investment requirements and financing needs. For example, with respect to gas resource supply, the cost
of gas exploration, treatment facilities, and supply systems is high. In addition, the energy resource plan
cannot circumvent market forces (i.e., devaluation of the Naira relative to U.S. dollars) from incentivizing
gas export by producers. Furthermore, there is little or no incentive to maintain existing gas pipelines or
ensure security of supply in the absence of activated gas supply agreements and persistent poor payment
for gas by GENCOs.
6.2.5 Generation Expansion Planning Impact
The absence of a Generation Expansion Plan makes it difficult to ensure enough generation capacity to
supply current and future demand loads, as well as reserve capacity for system reliability. Ignoring
transmission constraints, the total generation available of approximately 7,500 MW (~55 percent of
installed capacity) currently falls short from the estimated national load demand of approximately 11,000
MW.52
In addition, many generating units, specifically gas turbine units, have reached or are approaching the end
of their operational lifetime. These old units are susceptible to breakdowns and are causing more planned
maintenance outages. The need for an expansion plan is crucial to address existing plant refurbishments
or replacements. It is anticipated that a replacement need of up to 3000 MW of existing generation
capacity is expected within the next five to ten years.53
6.2.6 Energy Resource Planning Impact
Generation output is dependent on, but not limited to, the following: (1) the availability of generation
units; (2) gas supply for thermal power plants; and (3) water inflow for hydropower plants. The absence
of an adequate resource plan component of a Generation Expansion Plan is partially responsible for non-
operational generating units due to gas transmission constraints (e.g., pipeline size). It is fair to note that
in some cases gas supply is constrained and/or interrupted by the sabotage of the gas pipeline system. The
impact of gas constraints in 2016 rendered approximately 3,700 MW (~30 percent of installed capacity)
of generation capacity unavailable.54 An expansion plan can facilitate more detailed requirements for gas
exploration, gas treatment facilities, and gas supply systems (e.g., pipelines) to ensure the availability of
thermal power plant generation capacity.
52 NARUC Technical Assistance Project (2018) and Transmission Expansion Plan (Fichtner) 53 Transmission Expansion Plan (Fichtner) 54 Ibid
Building on the response to the Planning Challenge above, NPSP, in addition, could
assist the System Operator in facilitating planning workshops to communicate
generation expansion plans with stakeholders such as GENCOs, gas suppliers, NBET,
and other relevant public and private entities.
LONG-TERM PLANNING ASSESSMENT 29
7. CONCLUSION
The absence of an integrated approach to long-term system planning has resulted in an unreliable power
grid with misplaced infrastructure investments. Adopting an integrated planning approach can ensure
resources are allocated efficiently to reliably meet future load requirements. This assessment builds on
the USAID funded technical assistance project by NARUC to develop NERC’s capacity to evaluate system
planning and will guide future NPSP reform efforts, considering how stakeholder buy-in will make some
interventions more feasible than others. Based on the findings of this report, NPSP identifies the following
five priority short-term actions, subject to USAID approval:
1. Support NERC in finalizing a planning framework originating from the NARUC Technical
Assistance Project (2018) consultant and NERC;
2. Support NERC and the System Operator to organize an industry workshop with all system
participants to effectively communicate the steps towards effective planning;
3. Identify and form operational plans to address capacity gaps afflicting planning stakeholders;
4. Support the audit and verification of power sector infrastructure assets; and
5. Facilitate planning workshops communicating generation expansion plans with stakeholders such
as GENCOs, gas suppliers, NBET, and other relevant public and private entities.
NPSP will take into account other ongoing donor activities in order to mitigate any overlap and identify
any synergistic opportunities. NPSP is well aware that intervention activities may include a component of
data consolidation to account for the ongoing planning efforts and studies, such as the JICA Power Sector
Master Plan Study. NPSP acknowledges that future interventions face the challenges of: (1) a potential
change in leadership within FGN following the elections; and (2) the lack of stakeholder incentives to
engage in reform arising from inactive agreements and liquidity issues, among others.