Institutional Analysis of the
Implementation of Utility-Scale
Solar Projects in Ghana
JUNE 2022
Report No: AUS0002925
Ghana
Ghana Green Growth PASA
Institutional Analysis of the Implementation
of Utility-Scale Solar Projects in Ghana
June 2022
Environment, Natural Resources, and the Blue Economy Global Practice
© 2022 The World Bank
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Table of Contents
ACKNOWLEDGMENTS ...................................................................................................................I
ACRONYMS..................................................................................................................................II
1 INTRODUCTION ................................................................................................................... 1
1.1 Background of the Assignment .................................................................................................... 1
1.2 Objective of the Assignment ........................................................................................................ 1
1.3 Consultant’s Scope of Work ......................................................................................................... 1
1.4 Approach and Methodology ........................................................................................................ 1
2 GHANA’S RENEWABLE ENERGY TARGETS AND REQUIREMENTS ............................................ 4
2.1 Definition of Ghana’s Renewable Energy Targets ........................................................................ 4
2.2 Ghana’s Electricity Demand Forecast through 2030 .................................................................... 4
2.3 Renewable Energy Target and Generation Gap ........................................................................... 5
2.4 Solar Project Requirement to address the Renewable Energy Generation Gap ......................... 6
2.5 Transmission Considerations for Solar PV Project Implementation ............................................ 7
2.6 Implementation Scenarios for Solar PV Projects ......................................................................... 9
2.7 Plans of Utilities to Scale-Up RE in the Next Five Years ............................................................... 9
3 INVESTMENT REQUIREMENTS TO ADDRESS RE GAP ........................................................... 11
3.1 Solar PV Project Estimates and Investment Requirements ....................................................... 11
3.2 Transmission Requirements to Support New Solar PV Generation ........................................... 12
3.3 Total Investment Requirements to Achieve RE Target .............................................................. 17
4 LEGAL AND REGULATORY ASSESSMENT ............................................................................. 18
4.1 Utility Mandates for Regulated and Deregulated Markets ........................................................ 18
4.2 Ghana’s Competitive Electricity Procurement Policies .............................................................. 19
4.3 Assessment of Compliance with Utility Mandates..................................................................... 21
4.4 Assessment of Compliance with 2019 Competitive Procurement Policy .................................. 21
5 GHANA’S SOLAR PV PROJECTS AND FINANCE STRUCTURES ................................................ 22
5.1 Description of Solar PV Projects ................................................................................................. 22
5.2 Comparison of Solar PV Projects ................................................................................................ 24
6 ECONOMIC AND FINANCIAL ANALYSIS ............................................................................... 27
6.1 Indicators of Utility Creditworthiness ........................................................................................ 27
6.2 ECG’s Key Risks and Other Considerations................................................................................. 29
6.3 Generators’ Key Risks and Other Considerations ...................................................................... 30
6.4 Other Considerations – GRIDCo Operations .............................................................................. 32
6.5 Assessment of Fundraising and Financing Options .................................................................... 32
6.6 Summary of Market Debt Finance Options for Solar PV Projects .............................................. 33
6.7 Generation Cost Impact of Achieving the 10 Percent RE Target ............................................... 33
7 CONCLUSIONS AND RECOMMENDATIONS ......................................................................... 35
7.1 Project Financing Structures of Existing Solar Projects .............................................................. 35
7.2 Economic and Financial Analysis ................................................................................................ 36
7.3 Mandates and Responsibilities for Supply to Regulated and Deregulated Markets ................. 37
7.4 Solar PV Procurement Plans and Investments to Reach 10 Percent RE Commitment .............. 37
7.5 Recommendations ..................................................................................................................... 38
REFERENCES .............................................................................................................................. 40
Tables
Table 1: Electricity Demand Forecast (2022–2026) .......................................................................................................4
Table 2: Ghana Power System Electricity Demand Forecast (2022–2030) ....................................................................5
Table 3: RE Project Generation Forecast (2022–2030) ..................................................................................................5
Table 4: Renewable Energy Target Analysis Results ......................................................................................................6
Table 5: Solar Project Capacity Requirement to Address RE Generation Gap...............................................................6
Table 6: NITS Solar PV Generation Injection by Zone ....................................................................................................8
Table 7: NITS System Condition/Contingency Analysis .................................................................................................8
Table 8: Solar PV Penetration Scenarios by NITS Zone ..................................................................................................9
Table 9: Solar Project Pricing Summary .......................................................................................................................11
Table 10: Solar Project Modules Required to Fill RE Generation Gap .........................................................................12
Table 11: Investment Requirement for Solar PV Plants to Fill RE Generation Gap .....................................................12
Table 12: Population and Land Area of Ghana's Administrative Regions ....................................................................15
Table 13: Financial Estimates of Transmission Reinforcement Projects .....................................................................17
Table 14: Total Investment Requirements to Reach RE Generation Target in 2030 ...................................................17
Table 15: Forecast of Commercial and Performance Information of Solar PV Projects ..............................................22
Table 16: Price Adjustment Factors for Utility-Scale Solar PV .....................................................................................25
Table 17: Comparison of Equivalent Prices for Existing Solar PV in Ghana .................................................................26
Table 18: Key Financial Indicators for ECG ..................................................................................................................28
Table 19: Key Financial Indicators for VRA ..................................................................................................................28
Table 20: Key Financial Indicators for BPA ..................................................................................................................29
Table 21: Summary of Debt Financing Options and Terms .........................................................................................33
Table 22: Solar PV Project LCOE Summary of Results .................................................................................................34
Table 23: Cost Impact of New Solar Plants ..................................................................................................................34
Table 24: Summary of Existing and ‘Under-Construction’ Solar PV Projects' Financing Information .........................35
Table 25: Summary of Existing and ‘nder-Construction’ Solar PV Projects' Commercial and Performance Information
.....................................................................................................................................................................................35
Table 26: Summary of Utilities' Mandates and Creditworthiness ...............................................................................37
Table 27: Summary of Solar PV Project LCOE and Investment Requirements to Reach 10 Percent RE Target ...........38
Figures
Figure 1: Ghana Power System Electricity Demand Forecast (2022–2030) ..................................................................5
Figure 2: System RE Generation Gap Analysis (2022–2030)..........................................................................................6
Figure 3: Ghana NITS Zonal Configuration .....................................................................................................................7
Figure 4: Ghana Population Density Map by Region ...................................................................................................14
Figure 5: Solar PV Project Distribution and Placement Map .......................................................................................16
Figure 6: Benchmark Costs for Solar PV Systems (2010–2020) ...................................................................................25
Acknowledgments
This report was guided by a team led by David Vilar Ferrenbach and Maame Tabuah Ankoh. The report
was prepared by Arthur Energy Advisors [Amissah-Arthur Jabesh, Amissah-Arthur Jabesh K., Ofedie
Joshua, Sekor Emmanuel].
The report was produced under the overall guidance of Pierre Laporte (Country Director, Ghana) and
Sanjay Srivastava (Practice Manager, SAWE4).
The team would like to acknowledge the kind cooperation the Governments of Ghana counterparts who
provided necessary information needed for the analysis: Ministry of Energy, Energy Commission, Volta
River Authority, Bui Power Authority, Electricity Company of Ghana, Ghana Grid Company and Public
Utility Regulatory Commission
The team would also like to acknowledge the generous support provided for preparation of the report by
the Climate Support Facility, administered by the World Bank.
i
Acronyms
AT&C Aggregate Technical and Commercial
ATC&C Aggregate Technical, Commercial, and Collection
BGT Bulk Generation Tariff
BPA Bui Power Authority
BSP Bulk Supply Point
CAGR Compound Annual Growth Rate
CAPEX Capital Expenditures
CBGT Composite Bulk Generation Tariff
CR Current Ratio
DFI Development Finance Institution
DSC Distribution Service Charge
DSCR Debt Service Coverage Ratio
EC Energy Commission
ECG Electricity Company of Ghana
EOI Expression of Interest
EPC Engineering, Procurement, and Construction
ETU Electricity Transmission Utility
GoG Government of Ghana
GR Gearing Ratio
GRIDCo Ghana Grid Company
IPP Independent Power Producer
IPSMP Integrated Power System Master Plan
IRRP Integrated Resource and Resilience Planning
KfW Kreditanstalt für Wiederaufbau
LCOE Levelized Cost of Energy
MoEn Ministry of Energy
NDC Nationally Determined Contribution
NEDCo Northern Electricity Distribution Company
NITS National Interconnected Transmission System
NorFund Norwegian Investment Fund for Developing Countries
NREL National Renewable Energy Laboratory
PGCPES Policy Guidelines for Competitive Procurement of Energy Supply and Services Contracts
PPA Power Purchase Agreement
PURC Public Utilities’ Regulatory Commission
PV Photovoltaic
RE Renewable Energy
REFiT Renewable Energy Feed-In Tariff
REMP Renewable Energy Master Plan
RFP Request for Proposal
ROAE Return on Average Equity
RONFA Return on Net Fixed Assets
SNEP Strategic National Energy Plan
SOE State-Owned Entity
STATCOM Static Synchronous Compensator
USAID United States Agency for International Development
ii
USSE Utility-Scale Solar Energy
VRA Volta River Authority
WEM Wholesale Electricity Market
iii
1 Introduction
1.1 Background of the Assignment
The World Bank is exploring opportunities to accelerate climate action and low-carbon resilient
development pathways by supporting Ghana in enhancing and implementing its nationally determined
contribution (NDC).
One of the areas identified under the NDC is the support to increase utility-scale solar energy (USSE)
generation in the country which is in line with the policy action to increase the share of renewable energy
(RE) generation in Ghana’s energy mix. In preparation for this, the World Bank has commissioned this
consultancy assignment titled ‘Institutional Analysis of the Implementation of Utility-Scale Solar Projects
in Ghana.’
1.2 Objective of the Assignment
The overall goal of this consultancy services assignment, in the context above, was to
• Analyze the implementation structures of existing utility-scale solar projects and future solar
projects in the country and
• Assess the most appropriate project finance and institutional arrangement to scale up solar
projects in Ghana as a first step in the process.
1.3 Consultant’s Scope of Work
The consultant’s scope of work focused on the execution of the following:
• Review the project finance structures of existing solar projects executed by three utilities in
Ghana, namely, Electricity Company of Ghana (ECG), Volta River Authority (VRA), and Bui Power
Authority (BPA).
• Review the plans of these utilities to scale up in the next five years.
• Review the mandates of these three utilities to procure additional power capacity for the
regulated and nonregulated markets and how these would comply with the 2019 Competitive
Procurement Policy of the Ministry of Energy (MoEn).
• Perform an economic and options analysis describing the financial options and the project finance
structure of new solar power projects under each utility.
1.4 Approach and Methodology
The consultant executed the assignment by completing four primary tasks:
• Task 1: Project finance structure review
• Task 2: Utility generation and procurement plan review
• Task 3: Organizational mandate and procurement policy review
• Task 4: Economic, financial, and impact analysis.
1
The assignment was executed in three phases of activity covering aspects that enabled the consultant to
address each of the four tasks:
• Phase 1: Information gathering and review
• Phase 2: Analysis
• Phase 3: Reporting.
Phase 1. Information Gathering and Review
During this phase of activity, the consultant contacted the relevant power sector institutions to gather key
information which provided a basis for the analysis phase of activity (Activity 2). The information sought
included the following:
• Information on cost of generation, project structure, financing, and cost modeling was gathered
from BPA and the VRA.
• Key financial performance details typically contained in audited accounts were gathered from
each of the target utilities for the assignment—ECG, BPA, and VRA.
• Demand-Supply Projection Documents for the Ghanaian Power System through 2030 were
gathered from the regulators (Energy Commission [EC] and Public Utilities’ Regulatory
Commission [PURC]) and Ghana Grid Company (GRIDCo).
• Transmission-related assessment information was gathered from GRIDCo.
• Market lending rates were gathered from a selection of development finance and commercial
project finance lenders.
Activity 2. Analysis
First, the consultant utilized the documents and information gathered during Activity 1 to summarize the
utilities and power sector plans to identify and price the solar power projects and electricity generated
from solar power projects planned for execution or procurement by the utilities during the planning
period. During this activity, the consultant provided contextual information regarding the mandates of
the utilities and the compliance of their power project and electricity procurement plans with the MoEn’s
Competitive Procurement Policy. These covered the utilities’ participation in both regulated and
deregulated markets of Ghana’s power sector.
Second, the consultant summarized the project finance structures and relevant financial performance
indicators of existing solar projects executed by the utilities. The summaries of these structures were used
to inform the analysis of the economic and financial options toward addressing the requirements for Task
4.
Third, the consultant dispatched the identified solar power projects alongside the power sector’s demand-
supply projections to determine the impact of the addition of these solar projects on the achievement of
Ghana’s RE targets. Additionally, the consultant completed the economic, financial, and impact analysis
drawing on threshold analysis to assess the financial impact of the target utilities’ solar project
2
implementation and electricity procurement plans on generation costs during the planning period based
on assessed tariff or levelized cost of energy (LCOE) ranges.
Finally, the consultant analyzed the financial position of each utility to determine its capacity to leverage
various funding options including equity, balance sheet, and other funding and project structuring options
to establish projects.
Activity 3. Reporting
The consultant prepared and submitted three documents during the execution of this assignment.
• An ‘Inception Presentation’ summarized the consultant’s initial findings and work plan for
completion of the subsequent activities.
• A ‘Draft Report on Analysis and Recommendations’ summarized the consultant’s analyses,
findings, conclusions, and recommendations from the execution of the assignment.
• The ‘Final Report’ was submitted following receipt, satisfactory address, and incorporation of the
comments and suggestions from the client.
3
2 Ghana’s Renewable Energy Targets and Requirements
2.1 Definition of Ghana’s Renewable Energy Targets
In recent years, Ghana’s RE targets/commitments have been mentioned in several policy statements and
reports. But they interpret Ghana’s RE targets/commitments differently.
Some of the major national policy documents or statements of Ghana’s commitments on RE targets are
as follows:
• The Integrated Power System Master Plan (IPSMP) Volumes 1 to 4, published between 2017 and
2019 by ICF and the EC under USAID’s Integrated Resource and Resilience Planning (IRRP) Project,
offered analyses of RE targets under a methodology which focused on the percentage penetration
of RE as a proportion of Ghana’s off-peak capacity demand (in MW).
• The EC’s Strategic National Energy Plan (SNEP) 2030, which was published in July 2019, had a
stated goal of “achieving 10% renewable energy in the total national energy supply mix by 2030.�?
• The Renewable Energy Master Plan (REMP) aims to scale up RE penetration in the electricity grid
by 10 percent and increase total renewable energy to 1,363 MW by 2030.
For this assignment, the consultant and client have agreed to adopt the definition of Ghana’s RE
target/commitment as the goal of achieving 10 percent supply of annual electricity consumption (in GWh)
with 2030 as the target year.
2.2 Ghana’s Electricity Demand Forecast through 2030
The most recent electricity demand forecast for the Ghanaian power system, which the consultant could
access, was contained in the 2021 Electricity Supply Plan. This electricity forecast is presented in Table 1.
The 2021 Electricity Supply Plan’s projection ran from 2022 through 2026 and tracked an approximately
5.8 percent compound annual growth rate (CAGR) which increased the peak capacity demand from 3,539
MW in 2022 to 4,460 MW in 2026. The corresponding projected electricity system energy demand was
forecasted to grow from 22,799 GWh in 2022 to 28,550 GWh in 2026.
Table 1: Electricity Demand Forecast (2022–2026)
Item 2022 2023 2024 2025 2026
Peak Capacity Demand (MW) 3,539 3,739 3,964 4,171 4,460
Energy Demand (GWh) 22,799 24,177 25,572 27,069 28,550
Source: 2021 Electricity Supply Plan.
The consultant utilized the 5.8 percent CAGR from the 2021 Electricity Supply Plan to extrapolate both
the system peak capacity demand and energy demand through 2030. The resulting forecast (as shown in
Table 2 and illustrated in Figure 1) shows that, by 2030, the system peak demand and energy demand are
expected to grow to 5,588 MW and 35,772 GWh, respectively.
4
Table 2: Ghana Power System Electricity Demand Forecast (2022–2030)
Item 2022 2027 2028 2029 2030
Peak Capacity Demand
3,539 4,719 4,992 5,282 5,588
(MW)
Energy Demand (GWh) 22,799 30,206 31,958 33,811 35,772
Compound Annual Growth
5.8%
Rate (CAGR)
Figure 1: Ghana Power System Electricity Demand Forecast (2022–2030)
2.3 Renewable Energy Target and Generation Gap
RE Generation Projection
The consultant has assessed the RE landscape and developed an RE generation projection. From the
information gathered from power sector stakeholders, there are seven RE projects, of which six are
already operational. VRA’s Lawra project is under construction. The seven RE plants are projected to
produce a total of 162 GWh annually, as shown in Table 3.
Table 3: RE Project Generation Forecast (2022–2030)
Projected Annual Generation
RE Projects
2022 2023 2024 2025 2026 2027 2028 2029 2030
VRA Solar 1 - Navrongo 3 3 3 3 3 3 3 3 3
VRA Solar 2 - Kaleo 26.6 26.6 26.6 26.6 26.6 26.6 26.6 26.6 26.6
VRA Solar 3 - Lawra 10 10 10 10 10 10 10
BXC 27 27 27 27 27 27 27 27 27
Meinergy 27 27 27 27 27 27 27 27 27
Safisana 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7
Bui Solar Farm 1 68 68 68 68 68 68 68 68 68
Total RE Energy Generated (GWh) 152 152 162 162 162 162 162 162 162
Of the seven projects, four are owned/hosted by state-owned entities (SOEs) (that is, VRA and BPA) while
three (that is, Safisana, BXC, and Meinergy) are privately owned. Safisana also happens to be the only non-
solar project among the seven projects.
5
Renewable Energy Target
As identified in Section 0 above, the RE target adopted for this assignment is defined as 10 percent of the
Ghanaian electricity system’s annual energy demand or consumption (in GWh). Based on this definition,
the computed RE target for 2030 is 3,577 GWh (see Table 4).
Table 4: Renewable Energy Target Analysis Results
Item 2022 2023 2024 2025 2026 2027 2028 2029 2030
Energy Demand (GWh) 22,799 24,177 25,572 27,069 28,550 30,206 31,958 33,811 35,772
RE Target/Commitment 10%
RE Target (GWh) 2,280 2,418 2,557 2,707 2,855 3,021 3,196 3,381 3,577
RE Penetration (GWh) 152 152 162 162 162 162 162 162 162
RE Penetration (%) 0.7% 0.6% 0.6% 0.6% 0.6% 0.5% 0.5% 0.5% 0.5%
RE Generation Gap (GWh) 2,128 2,265 2,395 2,544 2,693 2,858 3,033 3,219 3,415
The seven forecasted RE projects generate approximately 162 GWh of electricity, leaving an RE generation
gap of 3,415 GWh, which means the RE penetration is only 0.5 percent against the target of 10 percent of
total supply. This implies that the seven plants together can only achieve the equivalent of 4.5 percent of
the RE target, leaving a substantial RE generation gap (as illustrated in Figure 2).
Figure 2: System RE Generation Gap Analysis (2022–2030)
2.4 Solar Project Requirement to address the Renewable Energy Generation Gap
Based on the expected performance of the solar projects, the consultant has determined the solar project
capacity required to generate sufficient electricity to address the RE generation gap. The results of this
analysis (presented in Table 5) show that the Ghanaian system requires over 2,500 MW of new solar
projects to be implemented by 2030 to reach the RE target/commitment.
Table 5: Solar Project Capacity Requirement to Address RE Generation Gap
Item 2022 2023 2024 2025 2026 2027 2028 2029 2030
RE Generation Gap (GWh) 2,128 2,265 2,395 2,544 2,693 2,858 3,033 3,219 3,415
Solar Project Capacity to Fill
1,564 1,666 1,761 1,871 1,980 2,102 2,230 2,367 2,511
RE Generation Gap (MW)
6
2.5 Transmission Considerations for Solar PV Project Implementation
Ideally, the implementation of solar photovoltaic (PV) plants should not contribute negatively to the
operation of the National Interconnected Transmission System (NITS). As stipulated under Ghana’s Grid
Code, GRIDCo is to operate the NITS within specified operating criteria for various NITS components and
indicators including the following:
• Transmission lines. GRIDCo requires lines to operate within their normal thermal ratings and up
to 110 percent under normal and short duration contingencies, respectively.
• Transformers. GRIDCo requires transformers to operate up to 100 percent and 120 percent of
their ratings under normal and contingency conditions, respectively.
• Substations. GRIDCo requires substations to operate within 5 percent and 10 percent bands of
the nominal system voltages and power factors under normal and contingency conditions,
respectively.
The consultant held discussions with GRIDCo staff regarding the constraints relating to the NITS for large-
scale solar project implementation. Many of the opinions expressed by GRIDCo with respect to the
viability of large-scale solar PV injection into the NITS were corroborated by the IPSMP’s Solar Photovoltaic
Penetration Study. Ideally, the implementation of solar PV plants should not contribute negatively to the
operation of the NITS but rather support the NITS to remain within acceptable operating limits.
Zonal NITS Capacity Considerations
The load patterns and geographic coverage of Ghana’s NITS are key determinants of the conditions under
which solar PV can be implemented to feed into the NITS. The Ghanaian NITS, which consists primarily of
161 and 330 kV transmission systems, has four primary operating zones, as shown in Figure 3.
Figure 3: Ghana NITS Zonal Configuration
Source: IPSMP,2019
7
A Solar PV Penetration Study carried out as part of the IPSMP had investigated the steady-state and
transient stability performance of the NITS under various scenarios which included the implementation
of solar PV projects at capacity levels of 310, 490, and 790 MW in the various NITS zones, as shown in
Table 7.
The study results were that the NITS can handle a combined peak injection of approximately 3,400 MW
of solar PV. The views of GRIDCo on the maximum possible solar PV capacity which can be injected across
nodes in each of the four zones were corroborated by the IPSMP (see Table 6).
Operating Requirements and Limits
In helping to complete the IPSMP, GRIDCo worked with ICF to provide high-level assessments of the
impact of various levels of solar PV penetration on the NITS. These assessments prioritized consideration
of the NITS’ system stability and operating requirements under areas including steady-state and transient
system conditions or contingencies.
The study results illustrated in Table 6 and Table 7 indicated that the implementation of up to 790 MW of
solar PV generation in the North Zone caused no major issues with steady-state voltage violations, line or
transformer overloads. However, the assessment showed that the implementation of more than 310 MW
of solar PV generation begins to affect the NITS’ transient stability under loss of major generator, three-
phase fault, and loss of major transmission line contingency scenarios. The effect of solar PV generation
on the NITS under transient stability scenarios shows that additional investments will be required to
reinforce or enhance the NITS to facilitate the injection of more than 310 MW without negative impacts
on grid performance.
Table 6: NITS Solar PV Generation Injection by Zone
Maximum
Configuration NITS Model Zone
Capacity (MW)
North 1,440
Ashanti 218
Solar PV
SouthEast 960
SouthWest 845
Total Max PV Capacity without Storage 3,463
Table 7: NITS System Condition/Contingency Analysis
Solar PV Capacity
System Condition/ Contingency (MW)
310 490 790
Voltage Violations
Steady State
Line or Transformer Overloads
Loss of Major Generator
Transient
Three-Phase Fault
Stability
Loss of Major Transmission Line
8
Source: IPSMP.
2.6 Implementation Scenarios for Solar PV Projects
An additional 2,511 MW of solar PV projects, as shown in Table 5, must be completed for the Ghanaian
power system to reach its RE target in 2030 using solar PV. The maximum solar PV capacity that can be
accepted by the NITS is approximately 3,400 MW, which, as shown in Table 6, exceeds the 2030 projected
solar PV project requirement of 2,511 MW. Therefore, under steady-state conditions, assuming solar PV
was used to fill the entire RE generation gap, the NITS should be able to absorb the electricity generated
from these projects. It should also be noted that the Ghanaian power system gets the greatest benefits in
terms of transmission losses and voltage support from solar PV plants sited in the North Zone of the
transmission network.
The distribution of solar PV generation under six scenarios, where solar PV is utilized to address the RE
generation gap, is as presented in Table 8. The three scenarios representing 100 percent, 75 percent, and
50 percent solar penetration within the RE generation gap were chosen by the consultant for further
consideration. The three scenarios equivalent to 31 percent, 20 percent, and 12 percent solar penetration
within the RE generation gap were intended to provide comparable assessment points covering the three
primary solar penetration assessments previously analyzed in the IPSMP.
As concluded by the IPSMP study, the North Zone of the NITS is capable of absorbing approximately 1,440
MW, which is equivalent to 59 percent of the solar PV capacity of 2,511 MW required to meet the RE
generation gap. Of the scenarios considered in Table 11, the Ashanti and SouthEast Zones of the NITS are
required to have solar PV injection only when RE penetration is to be higher than 75 percent and 100
percent of the target, respectively.
Table 8: Solar PV Penetration Scenarios by NITS Zone
Solar Penetration Scenarios
Solar Penetration Levels for
100% 75% 50% 31% 20% 12%
RE Generation Gap
Project Solar PV Generation (GWh) 3,415 2,561 1,707 1,074 666 422
Configuration Solar PV Capacity (MW) 2,511 1,883 1,255 790 490 310
North 1,440 1,440 1,255 790 490 310
Ashanti 218 218 - - - -
SouthEast 853 226 - - - -
Solar PV
SouthWest - - - - - -
Total Implemented 2,511 1,883 1,255 790 490 310
PV Capacity Outstanding - - - - - -
2.7 Plans of Utilities to Scale-Up RE in the Next Five Years
In the next five years, the utilities (BPA and VRA) will be working toward the following notable solar PV
project plans:
• BPA has signed contracts and is actively seeking funding to implement two solar PV projects
totaling 150 MW.
9
• VRA is developing a 60 MW solar PV plant to be located at Bongo, near Bolgatanga.
Both the BPA and VRA are working to secure offtakers and obtain financing for the projects.
ECG has no immediate plans for any additional power procurement, including RE, and is focused on
addressing issues related to the prevailing overcapacity. ECG is mandated as a distribution utility only and
therefore has no mandate for power generation. This means ECG is not mandated to implement RE and/or
solar PV generation projects.
The prevailing generation overcapacity in the Ghanaian power sector has made the preparation of new
solar PV projects and related power procurement, especially for the regulated market, a fairly challenging
activity for the utilities to justify, especially without apparent visibility of the end of the overcapacity
situation.
10
3 Investment Requirements to address RE Gap
3.1 Solar PV Project Estimates and Investment Requirements
Based on the sizes of recently implemented and planned projects encountered during the assignment,
the consultant identified that future solar PV projects are likely to be implemented as modules of 20, 50,
or 100 MW. To obtain prices for solar PV plants at 20, 50, and 100 MW, the consultant contacted solar PV
developers and engineering, procurement, and construction (EPC) service providers for pricing data. A
summary of the typical prices obtained by the consultant for various components of a fully functional solar
PV project is presented in Table 9.
Table 9: Solar Project Pricing Summary
Cost Category Item 20 MW 50 MW 100 MW
Solar PV Module $ 5,800,000 $ 14,500,000 $ 29,000,000
Inverter $ 800,000 $ 2,000,000 $ 4,000,000
Engineering, Mounting Structure $ 1,800,000 $ 4,500,000 $ 9,000,000
Procurement, & Electrical Balance of Plant $ 1,600,000 $ 4,000,000 $ 8,000,000
Construction (A) Installation & Labour $ 2,000,000 $ 5,000,000 $ 10,000,000
Power Evacuation Transformer $ 2,319,885 $ 2,319,885 $ 4,319,885
Total Cost $ 14,319,885 $ 32,319,885 $ 64,319,885
Feasibility Study $ 170,000 $ 170,000 $ 170,000
Environmental & Social Impact
$ 100,000 $ 100,000 $ 100,000
Project Preparation Assessment (ESIA)
(B) Grid Impact/ Interconnection Study $ 100,000 $ 100,000 $ 100,000
Land Acquisition ($15,000/Acre) $ 2,779,935 $ 5,559,870 $ 11,119,740
Total Cost $ 3,149,935 $ 5,929,870 $ 11,489,740
Statutory Energy Commission Licenses $ 30,000 $ 30,000 $ 30,000
Approvals Environmental Permit $ 5,000 $ 5,000 $ 5,000
(Permitting & Local Development Authority Permit $ 5,000 $ 5,000 $ 5,000
Licensing) (C ) Total Cost $ 40,000 $ 40,000 $ 40,000
Basic Solar Plant Costs (A) $ 14,319,885 $ 32,319,885 $ 64,319,885
Solar Plant Costs
Comparable Solar Plant Costs (A + B + C) $ 17,509,820 $ 38,289,755 $ 75,849,625
Calculated Basic Solar Plant Costs ($/kW) $ 716 $ 646 $ 643
Benchmarks Comparable Solar Plant Costs ($/kW) $ 875 $ 766 $ 758
The solar project pricing obtained has been categorized between basic and comparable solar plant
configurations for each of the project implementation modules (20, 50, and 100 MW). The basic solar
plant includes only EPC costs. The comparable solar plant includes all project cost components comprising
EPC, project preparation, and statutory approval costs. The comparable solar plant costs are intended to
provide a cost summary similar to the real total cost of implementing solar projects.
The data gathered and presented in Table 9 yield calculated cost benchmarks of US$716, US$646, and
US$643/kW for the 20, 50, and 100 MW basic solar plants, respectively. The same data also yield
calculated cost benchmarks of US$875, US$766, and US$758/kW for the 20, 50, and 100 MW comparable
solar plants, respectively.
11
The number of projects required for each module, if the RE generation gap was to be filled entirely using
the aforementioned modules for solar PV plants (that is, 20, 50, and 100 MW), is as presented in Table
10.
Table 10: Solar Project Modules Required to Fill RE Generation Gap
RE Generation Fulfillment Gap Scenarios
Solar Penetration Levels
100% 75% 50% 25% 31% 20% 12%
for RE Generation Gap
Solar PV Generation
3,415 2,561 1,707 854 1,074 666 422
(GWh)
Solar PV Capacity (MW) 2,511 1,883 1,255 628 790 490 310
20 126 95 63 32 40 25 16
Solar Project
50 51 38 26 13 16 10 7
Modules
100 26 19 13 7 8 5 4
Table 11: Investment Requirement for Solar PV Plants to Fill RE Generation Gap
RE Generation Fulfillment Gap Scenarios
Solar Penetration Levels
100% 75% 50% 25% 31% 20% 12%
for RE Generation Gap
Solar PV Generation
3,415 2,561 1,707 854 1,074 666 422
(GWh)
Solar PV Capacity (MW) 2,511 1,883 1,255 628 790 490 310
20 Basic $ 1,843 $ 1,382 $ 921 $ 461 $ 580 $ 360 $ 228
20 Comparable $ 2,243 $ 1,682 $ 1,122 $ 561 $ 706 $ 438 $ 277
Implementation
50 Basic $ 1,623 $ 1,217 $ 812 $ 406 $ 511 $ 317 $ 200
Configuration &
50 Comparable $ 1,923 $ 1,442 $ 961 $ 481 $ 605 $ 375 $ 237
Cost ($' millions)
100 Basic $ 1,615 $ 1,211 $ 807 $ 404 $ 508 $ 315 $ 199
100 Comparable $ 1,904 $ 1,428 $ 952 $ 476 $ 599 $ 372 $ 235
The corresponding estimates of the capital investments required for establishing solar PV plants that
enable the attainment of various penetration levels of the RE generation gap based on basic and
comparable project pricing at various modular project sizes (20, 50, and 100 MW) have been determined
and presented in Table 11. Of the project configurations presented toward filling the RE generation gap
of 2,511 MW in full, the 20 MW comparable module presents the highest investment cost of US$2,243
million while the 100 MW basic module presents the lowest investment cost of US$1,615 million.
3.2 Transmission Requirements to Support New Solar PV Generation
Planned NITS Investments and Reinforcement Activities
GRIDCo recognizes the need to reinforce the NITS to support electricity supply quality across Ghana. This
year, GRIDCo expects to commence several critical projects intended to improve the NITS’ performance
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in critical ways including transfer capacity, system efficiency or losses, reliability, and quality of supply
(primarily focused on voltage stability). The projects include
• Reconstruction and upgrade of the 161 kV Aboadze-Takoradi-Tarkwa-Prestea and 161 kV Bogoso-
Dunkwa-New Obuasi transmission lines;
• Construction of a 330/161 kV substation at Dunkwa-on-Offin;
• Construction of a third bulk supply point (BSP) in Kumasi;
• Reconstruction and upgrade of the 161 kV A3BSP-Achimota transmission line; and
• Installation of a 60 MVAr static synchronous compensator (STATCOM) in Kumasi.
GRIDCo is considering the implementation of a second double-circuit 330 kV line from Dunkwa-on-Ofin
through Bui, Kintampo, and Tamale and on to Bolgatanga.
GRIDCo’s listed priority projects for 2022 should increase the NITS’ transfer capacity and grid performance
primarily between and within the SouthWest, SouthEast, and Ashanti Zones. Considering that the NITS
improvements are to be gained from GRIDCo’s listed priority projects, the largest proportion of solar PV
projects to be implemented to address the RE generation gap should be in the North Zone. The additional
NITS improvement projects will have the primary purpose of improving grid resilience and transfer
capacity within and between the North Zone and Ghana’s primary load centers in the Ashanti, SouthEast,
and SouthWest Zones.
Distribution and Placement of Solar Projects
To facilitate the assessment of the NITS’ project and investment requirements to support solar PV
projects, the consultant adopted a methodology which involved the consideration of solar PV projects in
groupings totaling 400 to 650 MW each for injection in various geographic areas and their associated
transmission lines across the NITS. In selecting the placement of these grouped projects, the consultant
considered several factors including
• Ghana’s population and its distribution, as shown on Ghana’s population density maps in Figure
4, and
• GRIDCo’s NITS operational priorities around loss reduction and system performance
enhancements.
First, the population distribution is an important consideration; given that the solar PV projects will take
up significant land areas, it is preferred for the targeted project areas to be sparsely populated to facilitate
the acquisition and use of large tracts of, at least, reasonably contiguous land. Second, the
implementation of these solar PV projects should be in areas of the grid where the projects can contribute
to reduced NITS losses because of long power transport distances from generation plants to load centers.
The long power transport distances also contribute to ‘quality of supply’ issues, especially in the
northernmost parts of the NITS. At present, the least generation dense portion of the NITS is in the areas
selected.
13
Figure 4: Ghana Population Density Map by Region
Source: Geo-Ref.net.
14
Table 12: Population and Land Area of Ghana's Administrative Regions
Area Density
Region ISO Capital Population
(km²) (pers/km²)
Greater Accra GH-AA Accra 3,245 5,446,237 1,678.3
Central GH-CP Cape Coast 9,826 2,859,821 291.0
Ashanti GH-AH Kumasi 24,389 5,432,485 222.7
Volta GH-TV Ho 9,504 1,649,523 173.6
Eastern GH-EP Koforidua 19,323 2,917,039 151.0
Western GH-WP Sekondi-Takoradi 13,847 2,057,225 148.6
Upper East GH-UE Bolgatanga 8,842 1,301,221 147.2
Bono GH-BO Sunyani 11,107 1,208,965 108.8
Ahafo GH-AF Goaso 5,193 564,536 108.7
Northern GH-NP Tamale 25,448 2,310,943 90.8
Western North GH-WN Wiawso 10,074 880,855 87.4
North East GH-NE Nalerigu 9,074 658,903 72.6
Oti GH-OT Dambai 11,066 747,227 67.5
Bono East GH-BE Techiman 23,257 1,203,306 51.7
Upper West GH-UW Wa 18,476 904,695 49.0
Savannah GH-SV Damongo 35,862 649,627 18.1
Total 238,533 30,792,608 129.1
Based on the factors of NITS operational priorities and population distribution, the consultant concluded
that a grouping of solar projects in the northern third of Ghana would have the best chance of being
feasibly implemented to meet Ghana’s RE target while contributing to enhanced NITS performance. The
proposed distribution of the solar PV projects is illustrated in Figure 5.
The four 400–650 MW groupings of solar PV projects have been distributed and placed as follows:
• Group A - 650 MW grouping along the Yapei-Salaga-Kpandai stretch of the NITS
• Group B - 650 MW grouping along the Yendi-Tamale stretch of the NITS
• Group C - 650 MW grouping along the Tamale-Bolgatanga stretch of the NITS
• Group D - 650 MW grouping along the Bui-Sawla-Wa stretch of the NITS.
15
Figure 5: Solar PV Project Distribution and Placement Map
Transmission Grid Projects to support Solar PV Projects
To appropriately support the implementation of new solar PV projects without diminishing the NITS’
performance and assuming the distribution and placement of solar PV projects are as shown in Figure 5,
from discussions with GRIDCo staff, the following grid enhancement projects and related investments (as
shown in Table 13) will be required for the reasons indicated.
• An additional 330 kV double-circuit line from Dunkwa-on-Ofin through Bui-Tamale-Bolgatanga
which will support power evacuation from Groups C and D. This line will be required to help
16
improve overall grid stability, reliability in contingency scenarios, and transfer the power
generated in the North Zone, especially during the day, to large load centers such as Kumasi and
Dunkwa-Obuasi areas.
• An upgrade of the 161 kV Kadjebi-Nkwanta-Salaga line to support power evacuation from Group
A. The current line is operated at 69 kV and requires some enhancements to function fully at its
rated voltage and provide sufficient power transfer capacity.
• An upgrade of the 161 kV Yendi-Tamale line to a double-circuit line to support power evacuation
from Group B. The current line is a single circuit line and requires upgrading to provide sufficient
power transfer capacity for Group B. Additionally, this upgrade would help reinforce overall
power transfer from both Group A and Group B by forming a ring circuit through Tamale-Yapei.
• At least one 60 MVAr STATCOM per 650 MW project grouping to help improve grid voltage
stability and power factor performance in each region where the project groupings are deployed.
Table 13: Financial Estimates of Transmission Reinforcement Projects
3.3 Total Investment Requirements to Achieve RE Target
The combination of solar PV project and transmission investments yields the total budgetary
requirements for Ghana to reach its RE target in 2030. Table 14 shows that it will take US$2,088–2,716
million to complete the solar PV and transmission projects required to achieve the RE target while, at
least, maintaining the NITS’ performance levels.
Table 14: Total Investment Requirements to Reach RE Generation Target in 2030
Investment Requirements (in $'
Solar PV Project
millions)
Configuration
Project Transmission Total
20 Basic $ 1,843 $ 2,316
20 Comp $ 2,243 $ 2,716
50 Basic $ 1,623 $ 2,096
$ 473
50 Comp $ 1,923 $ 2,396
100 Basic $ 1,615 $ 2,088
100 Comp $ 1,904 $ 2,377
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4 Legal and Regulatory Assessment
4.1 Utility Mandates for Regulated and Deregulated Markets
This section discusses the policies and institutional and regulatory framework for utility-scale solar PV
plants as well as the evolution of the legal mandates of the target institutions, EGC, VRA, and BPA.
Electricity Company of Ghana
ECG, the state-owned distribution service provider in Southern Ghana, was transformed in 1997 from a
statutory corporation into a company registered under the Companies Act of Ghana 1963 (Act 179) with
the Government of Ghana (GoG) as the sole shareholder. The company, per its constitution, was
established to
• Acquire the entirety of the business including the assets and liabilities of the predecessor
corporation;
• Construct, operate, and maintain its distribution facilities or sub-transmission systems, defined
under the Electricity Distribution Code as facilities and equipment operated below 34.5 kV;
• Purchase electricity from VRA or other suppliers for distribution; and
• Transmit, supply, and distribute electricity.
As a distribution utility and a participant in the regulated market as part of Ghana’s wholesale electricity
market (WEM), ECG falls under the regulatory purview of the EC and PURC. In accordance with the
provisions of Act 541 (EC Act), ECG is subject to licensing and technical regulation mandates of the EC
(Sections 24 and 27 of Act 541).
Like all distribution utilities, its rates and charges are subject to the approval of the PURC (Section 26(1)(a)
of Act 541). The PURC also oversees the customer services matters of these entities. The company
operates under a distribution license granted by the EC under the EC Act and the Commission’s Licensing
Guidelines.
Volta River Authority
The Volta River Development Act 1961 (Act 46), which established VRA in 1961, has since been amended
a few times. As a result of the amendments, the current mandates enable VRA to undertake the functions
of generating electricity by means of water power of the Volta River and any other means and supplying
electricity through the transmission system, including constructing a dam and power station near
Akosombo.
VRA was also granted powers for management of the water resources of the lake and the administration
of certain adjoining lands. VRA was also granted power to purchase electricity to meet its contractual and
other obligations (Section 10 of the Volta River Development Act, as amended).
With regard to power generation, VRA is mandated to supply electricity to
• The regulated market’s distribution companies including ECG, Northern Electricity Distribution
Company (NEDCo), and Enclave Power Company;
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• The deregulated market’s bulk consumers;
• The Akosombo and Kpong townships; and
• Any other customer under an arrangement agreed upon by the government and BPA.
Bui Power Authority
The Bui Power Authority Act 2007 (Act 740) established BPA to develop the hydroelectric power project
on the Black Volta River at Bui and any other potential hydroelectric power sites on the Black Volta River.
Specifically, BPA was to plan, execute, and manage the Bui hydroelectric power project which comprised
• The generation of electrical power for general industrial and domestic use;
• The construction of the transmission system to evacuate the power generated into the national
grid; and
• The supply of electricity generated at the dam to licensed distribution and transmission utilities,
the township of Bui and its environs, and other consumers in Ghana or elsewhere under
arrangements agreed on between the government, BPA, and the consumer.
BPA was also given the responsibility of managing the water resources and providing the facilities for
developing the lake for multipurpose use (Section 11 of Act 740).
The functions of BPA were expanded under the BPA Amendment Act 2020 (Act 1046). By the amendment,
BPA is to perform, in accordance with the Renewable Energy Act on behalf of the state, RE functions as
assigned by the Minister for Energy. These functions include
• Execution of RE projects,
• Management of RE assets, and
• Undertaking of RE activities for generating electric power (Section 2(b) and (c)).
4.2 Ghana’s Competitive Electricity Procurement Policies
History of Ghana’s Renewable Energy Policies
The legal and regulatory framework for RE development in Ghana has evolved over three distinct phases.
The first phase was pre-2011 when RE projects were developed under the existing traditional regulatory
regime unintentionally skewed in favor of the predominant conventional energy sources.
The second phase was the Renewable Energy Act 2011 (Act 832) period when legislation dedicated to the
promotion of renewables was first enacted introducing, among others, the RE purchase obligation and as
well as the renewable energy feed-in tariff (REFiT) mechanism.
The third phase and current regime commenced in 2020 with the passage of the Renewable Energy
(Amendment) Act 2020 (Act 1045). Important innovations of Act 1045 include the discontinuance of the
REFiT scheme and adoption of the competitive procurement method through competitive bidding or
auctions for public utilities, operators in the regulated market, extension of purchase obligation to
generators employing fossil fuels, and renewed focus on the development of solar rooftop systems.
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2019 Competitive Procurement Policy
In May 2019, the MoEn issued the Policy Guidelines for Competitive Procurement of Energy Supply and
Services Contracts (PGCPES). The objective of the policy was to ensure that Ghana procures energy in a
sustainable and least-cost manner to meet demand based on principles of transparency and open
competition underpinned by regulator-approved, regularly updated demand projections determined
through a comprehensive planning process. The PGCPES gave the sector regulators the responsibility of
ensuring that energy supply, including RE power, is procured through the rigorous master planning and
competitive procurement process.
The 2019 Competitive Procurement Policy consists of two primary steps:
• Supply deficit assessment
• Electricity supply procurement
First, the EC’s procurement procedure for the entire WEM commences from the indicative planning stage
aimed at establishing the source and magnitude of any current or forecasted supply deficits. New power
plants may only be procured in accordance with the requirements of the indicative plan.
Second, the distribution utilities and electricity transmission utilities (ETUs) must complete a seven-stage
process. Bulk consumers are also encouraged but not obliged to procure electricity supplies through a six-
stage competitive bidding process.
Electricity Procurement Process
The procurement process to be followed by the distribution utilities and ETUs for the regulated market is
as follows:
(a) Request for expression of interest (EOI)
(b) Short-listing of bidders
(c) Request for proposals (RFP) based on best practices requesting separate
(i) Technical proposal and
(ii) Financial proposal
(d) Evaluation of bids and selection of successful bidder
(e) Execution of the Power Purchase Agreement (PPA)—which is to be done in consultation with the
PURC
(f) EC licensing and siting approvals
(g) Construction and operation.
The distribution utilities and ETUs are required to employ World Bank Procurement Guidelines as well as
comply with the requirements of the Public Procurement Act.
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4.3 Assessment of Compliance with Utility Mandates
The following were the key takeaways from the consultant’s review of the mandates of the target utilities:
• By Ghana’s power sector regulations, ECG is not permitted to supply electricity to participants in
the deregulated market.
• ECG, in conjunction with the regulatory and approval processes of the PURC and EC, is responsible
for purchasing electricity supplies for customers in its operational areas.
• Both BPA and VRA are permitted to supply electricity to any regulated or deregulated market
participants. Neither entity is obliged to provide electricity supplies to customers in either
electricity market segments unless otherwise contractually obligated.
4.4 Assessment of Compliance with 2019 Competitive Procurement Policy
The following were the key takeaways from the consultant’s review of the target utilities’ compliance with
the 2019 Competitive Procurement Policy:
• Since the initiation of the 2019 Competitive Procurement Policy, three solar PV projects have been
concluded—VRA’s 17 MW Kaleo Solar Project, BPA’s 50 MW Solar Project, and VRA’s 6.5 MW
Lawra Solar Project which is under construction.
• Of these three projects, BPA’s 50 MW and VRA’s 6.5 MW solar PV projects have regulated market
offtakers (ECG and NEDCo). Because of the offtake by regulated market participants, these
projects were supposed to be subject to the 2019 Competitive Procurement Policy.
• The consultant was unable to establish that the actions recommended in the 2019 Competitive
Procurement Policy had been followed as part of the establishment of the projects completed
before 2019.
• In the case of the post-policy implementation of BPA’s 50 MW and VRA’s 6.5 MW solar PV
projects, the consultant found no evidence that the policy-recommended step had been initiated
toward the procurement of either project.
• While the embargo on new utility-scale generation projects has been in place, state-owned
generation companies (VRA and BPA) have been aggressively pushing forward with new solar
projects by leveraging their existing competitive advantages in the form of access to land, in-
house ancillary support (that is, backup power), existing power evacuation infrastructure, and
other support services.
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5 Ghana’s Solar PV Projects and Finance Structures
Several solar PV projects in the Ghanaian power system are either operational or in the final stages of
development:
• The 2.5 MW VRA Solar PV Plant located near Navrongo
• The 20 MW BXC Solar PV Plant located at Gomoa Onyandze near Winneba
• The 20 MW Meinergy Solar PV Plant located at Gomoa Onyandze near Winneba
• The 17 MW VRA Solar PV Plant located near Kaleo
• The 6.5 MW VRA Solar PV Plant located near Lawra
• The 50 MW Bui Solar PV Plant 1 located near the Bui Dam.
A summary of key commercial and performance information on each of these projects is provided in Table
15.
Table 15: Forecast of Commercial and Performance Information of Solar PV Projects
Expected First Year
Capacity Tariffs
RE Projects Energy of
(MW) (US$/kWh)
(GWh) Operation
VRA Solar 1 - Navrongo 2.5 3 0.1725 2013
VRA Solar 2 - Kaleo 17 26.6 0.0950 2020
VRA Solar 3 - Lawra 6.5 10 0.0900 2023
BXC 20 27 0.2014 2016
Meinergy 20 27 0.1825 2018
Bui Solar Farm 1 50 68 0.1024 2021
5.1 Description of Solar PV Projects
The 2.5 MW Navrongo Solar PV Plant
The 2.5 MW Navrongo Solar PV Plant is a VRA plant located near Navrongo in the Upper East Region of
Ghana. This plant is operational and was financed entirely by VRA equity. The electricity generated from
the plant is entirely committed to NEDCo as its offtaker at a tariff of US$0.1725/kWh. The plant evacuates
its generation through an embedded distribution network connection to NEDCo.
The 20 MW BXC Solar PV Plant
The 20 MW BXC Solar PV Plant is an independent power producer (IPP) located near Winneba in the
Central Region of Ghana. This plant is operational. The stakeholders have not been forthcoming with the
source of financing and the terms, but the consultant believes that the plant may have been financed by
an export credit facility from China. The electricity generated from the plant is entirely contracted to ECG
as its offtaker at a tariff of US$0.2014/kWh. The plant evacuates its power through ECG’s local medium-
voltage network.
22
The 20 MW Meinergy Solar PV Plant
The 20 MW Meinergy Solar PV Plant is an IPP located near Winneba in the Central Region of Ghana. This
plant is operational. The participants in this project have not been forthcoming with information on the
source of financing and the terms, but the plant is believed to have been financed by an export credit
facility from China. The electricity generated from the plant is entirely contracted to ECG as its offtaker at
a tariff of US$0.1825/kWh. The plant evacuates its power through ECG’s local medium-voltage network.
The 17 MW Kaleo Solar PV Plant
The 17 MW Kaleo Solar PV Plant is a VRA plant located near Kaleo in the Upper West Region of Ghana.
This plant is operational and was financed by concessional loans from Kreditanstalt für Wiederaufbau
(KfW), a German state-owned investment and development bank, covering 80 percent of the project’s
cost at an interest rate of 1 percent, with a repayment term of 40 years and a grace period of seven years.
The electricity generated from the plant is entirely committed to Newmont Ahafo as its offtaker at a tariff
of US$0.095/kWh. The plant evacuates its generation through an embedded distribution network
connection to NEDCo.
The 50 MW Bui Solar PV Plant 1
The 50 MW Bui Solar PV Plant 1 is located near the Bui Dam in the Bono Region of Ghana. This plant is
operational. The plant has been developed through an arrangement with the developers of the Meinergy
project and is also believed to have been financed by an export credit facility from China. The electricity
generated from the plant is entirely supplied to ECG under BPA’s existing PPA at a tariff of
US$0.1024/kWh. The plant evacuates its generation through the existing 161 kV substation that is
connected to the NITS.
The 6.5 MW Lawra Solar PV Project
The 6.5 MW Lawra Solar PV Project is a VRA project located near Lawra in the Upper East Region of Ghana.
This plant is under construction. Like VRA’s Kaleo Solar PV Plant, this project is financed by concessional
loans from KfW covering 80 percent of the project’s cost at an interest rate of 1 percent, with a repayment
term of 40 years and a grace period of 7 years. The electricity generated from the plant is entirely
committed to NEDCo as its offtaker at a tariff of US$0.09/kWh. The plant evacuates its generation through
an embedded distribution network connection to NEDCo.
Other Solar PV Plant Projects
The BPA is understood to be at various stages of implementing multiple solar PV projects. First, a 1 MW
Floating Solar Plant has been completed and is operational. Second, the BPA is also understood to have
signed a development contract for an additional 100 MW of solar PV with the developers of the Meinergy
project, who also implemented the BPA’s 50 MW Solar PV Project 1. Finally, it is understood that the BPA
is in discussions with KfW about potentially procuring for this project a concessionary loan similar to those
provided for VRA’s Kaleo and Lawra solar projects.
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5.2 Comparison of Solar PV Projects
This section presents the consultant’s comparison of Ghana’s existing solar PV projects.
Comparison of Offtake Arrangements
It is noted that outside of the VRA’s Lawra project, which is contracted to Newmont Ahafo, the offtakes
of the remaining parastatal-owned solar PV projects are all contracted to the regulated market (primarily
ECG and NEDCo) under existing wholesale supply arrangements.
Regarding the offtakes of the projects contracted for supplies to the regulated market (ECG and NEDCo),
it is recognized that none of the projects were competitively procured. The two IPP projects, BXC and
Meinergy, are contracted to ECG as its regulated market offtaker.
Comparison of Financing and Tariffs
As far as the consultant understands, none of the solar PV projects implemented so far have been project
financed. Outside of the Navrongo project that was funded entirely with equity, VRA’s other solar PV
projects have been implemented with concessional loans from KfW.
It has been observed that tariffs for solar PV projects have generally dropped from above US¢10/kWh to
less than US¢6/kWh . The most recent projects with tariffs less than 10 US Cents/kWh have been
implemented by BPA and VRA. These projects benefit from varying forms and levels of statutory leverage
and, in some cases, concessional loans, without any comparable private sector PV projects implemented
in the same timeline. It is therefore difficult to assess whether these tariffs are because of the statutory
advantages or they reflect a new and improved price point that can be indicative for future tariffs for all
solar PV projects including private-led ones.
Comparison of Implementation Costs and Tariffs
The solar PV projects operating in Ghana have been implemented over a decade. During this period,
fundamental shifts in the pricing of solar PV facilities have occurred. Also, several significant changes in
the policy environment have affected the pricing of solar PV generation, making any direct comparisons
of their implementation or unit costs of supply contentious and debatable.
The notable changes that have occurred during this period include
• Change in Ghana’s RE pricing regime from REFiT to competitive procurement,
• Varying implementation models,
• Significant differences in their financing arrangements, and
• Global reduction in solar PV implementation costs (as shown in Figure 6).
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Figure 6: Benchmark Costs for Solar PV Systems (2010–2020)
Source: National Renewable Energy Laboratory (NREL).
The benchmark costs from the NREL (see Figure 6) have been used to derive the adjustment factors that
would translate the costs or applicable tariffs for the various plants to prices of the base year 2020 for a
more equitable comparison. The computed adjustment factors are as shown in Table 16.
Table 16: Price Adjustment Factors for Utility-Scale Solar PV
Benchmark Values for Utility-Scale Solar PV (Source: NREL) Assumed
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Benchmark Prices
4.75 4.08 2.77 2.13 1.97 1.93 1.53 1.08 1.08 0.95 0.94 0.94 0.93 0.93
(Fixed Tilt)
Adjustment Factor
20% 23% 34% 44% 48% 49% 61% 87% 87% 99% 100% 100% 101% 101%
(BaseYear = 2020)
As noted earlier, the implementation dates for the existing solar PV plants vary. Therefore, recognizing
the global rate of fall in solar system prices, the comparable equivalent unit price for each of these plants,
as adjusted using the factors from Table 16, are as presented in Table 17.
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Table 17: Comparison of Equivalent Prices for Existing Solar PV in Ghana
First Year of Tariffs Equiv. Tariff
Solar Projects
Operation (US$/kWh) (Base Year = 2020)
VRA Solar 1 - Navrongo 2013 0.1725 0.0761
VRA Solar 2 - Kaleo 2020 0.0950 0.0950
VRA Solar 3 - Lawra 2023 0.0900 0.0910
BXC 2016 0.2014 0.1237
Meinergy 2018 0.1825 0.1588
Bui Solar Farm 1 2021 0.1024 0.1024
The results presented above indicate that the VRA Solar 1 - Navrongo plant has the most competitive unit
cost of supply while the Meinergy plant is providing the least competitively priced solar energy. These
comparisons, however, do not consider the differences in financing terms, ownership, and risk allocation,
especially where the plants are privately owned as against state utility owned.
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6 Economic and Financial Analysis
This section discusses, among others, the financial performance of ECG, BPA, and VRA. While noting ECG’s
role as an electricity distribution utility and the roles of BPA and VRA as generators, the context and
perspective for discussion of the financial performance, creditworthiness, and ability to raise financing
are viewed considering each organization’s mandated function in the unbundled energy sector.
In view of the restrictive mandate of ECG which precludes it from obtaining financing for generation
projects, there is no consideration of ECG’s ability to raise financing for generation projects directly. The
discussion of ECG’s financial performance therefore focuses entirely on its creditworthiness to continue
to secure or purchase electricity from generators or wholesale suppliers.
The discussion of the performance of BPA and VRA focuses on their ability to raise financing for generation
projects, including solar PV projects. The current power sector regulations, however, do not permit ECG
to raise financing to execute generation projects.
The energy offtake of ECG in 2020, for example, accounted for 40 percent of VRA’s production and all of
BPA’s production. Being Ghana’s largest distribution utility, ECG’s financial performance has a cascading
effect on all other participants in the electricity supply chain. Furthermore, ECG being the primary offtaker
for VRA and BPA, its financial performance has a particularly direct and corresponding effect on the
financial performance of these two entities.
6.1 Indicators of Utility Creditworthiness
To empirically discuss the ability of the utilities to access financing for various projects, the consultant
considered the following performance indicators:
• Current ratio (CR). This indicator is calculated by dividing current assets by current liabilities. This
indicator shows a company’s ability to cover its near-term obligations. The minimum
recommended CR is 1. From a lending perspective, having a CR less than 1 means a company does
not have sufficient assets to cover its liabilities. This tends to be a concern, particularly for
collateralized lending.
• Debt service coverage ratio (DSCR). This indicator is calculated by dividing earnings before
interest and taxes by the current portion of a company’s long-term obligations. This ratio is
typically utilized as a significant indicator to demonstrate to lenders that a company will have
enough future cash flow to cover its debt obligations. Typically, the minimum desired DSCR is
approximately 1.2x; the strictest lenders can require a DSCR as high as 1.5x.
• Gearing ratio (GR). This ratio is a measurement of an entity’s leverage. It shows the extent to
which a company’s operations are funded by equity funds versus debt financing. A company with
higher leverage (higher use of debt finance) could be at higher risk of default should there be a
negative change in the business environment, especially when the same company has a low DSCR.
• Return on average equity (ROAE). This is a ratio that measures the performance of a company
based on its average shareholders’ equity and it is calculated by dividing the net income at the
end of the fiscal year by the average of shareholders’ equity at the beginning and the end of the
year. It is one measure of the company’s profitability.
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• Return on net fixed assets (RONFA). This metric is calculated by dividing the net income for the
fiscal year by the average of the net fixed assets at the beginning and end of the fiscal year under
consideration. This indicator shows the efficiency with which an entity can turn a profit from its
fixed assets. The higher the return, the more efficient the operation of the assets and the firm.
ECG Creditworthiness
From 2017 through 2019, ECG had suboptimal performance in terms of DSCR, CR, and RONFA. In those
years, ECG recorded negative DSCR values. This is a troubling sign for lenders because it indicates a lack
of income toward meeting-long term liabilities. However, in 2020, it appears that an uptick in payment
from the GoG was sufficient to improve ECG’s performance on the key indicators.
As far as indicators are concerned, RONFA is especially relevant for ECG’s creditworthiness as its earnings
are largely based on transactional volume rather than its own productivity. ECG’s assets do not, by the
company’s activities, produce a sellable product as it buys the same product (electricity) from generators
that it sells to consumers.
Table 18: Key Financial Indicators for ECG
Indicator 2017 2018 2019 2020
Revenue (GHS) 6,219 5,906 7,283 6,913
Gearing Ratio
DSCR -0.32 -1.94 -2.11 1.78
Current Ratio 0.64 0.41 0.49 0.62
Return on Net Fixed Assets -4% -16% -8% 4%
VRA Creditworthiness
The key indicators for assessing VRA’s creditworthiness are summarized in Table 19.
Table 19: Key Financial Indicators for VRA
Indicator 2016 2017 2018 2019 2020
Revenue (GHS millions) 2,562 2,633 3,001 3,891 3,793
Gearing Ratio 26% 27% 27% 9% 9%
DSCR 0.02 0.61 0.71 0.9 0.77
Current Ratio 0.68 0.99 1.17 1.16 1.18
Return on Average Equity -5% 16% 9% 10% 10%
Return on Net Fixed Assets -2% 10% 8% 10% 10%
The indicators show that between 2016 and 2020, VRA recorded a 9.9 percent ROAE even though there
was a slight reduction in revenue for 2020. This illustrates the productivity of VRA’s use of its fixed assets.
Over the same period, VRA’s GR declined from 27 percent in 2017 to less than 9 percent in 2020. This
illustrates the improvement in the strength of its balance sheet and its ability to acquire more debt for
projects, if required. VRA’s CR has also increased during the same period and has been above 1 since 2018.
This demonstrates VRA’s relatively improved ability to cover its short-term obligations more reliably.
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However, VRA’s DSCR remains below 1 and might be a cause for concern if there are plans to use VRA’s
balance sheet to take on more debt as long-term financing for a project. VRA’s DSCR would have to rise
above 1.2 to 1.5 consistently for the utility to be viewed as able to reliably cover its debt obligations.
BPA Creditworthiness
The key indicators for assessing BPA’s creditworthiness are summarized in Table 20.
Table 20: Key Financial Indicators for BPA
Indicator 2016 2017 2018 2019
Revenue (US$ millions) $ 105.93 $ 98.96 $ 58.78 $ 95.72
Gearing Ratio 2.01 1.96 1.84 1.72
DSCR 1.62 1.84
Current Ratio 7.72 5.39 10.57 14.73
Return on Average Equity 19% 9% 18% 14%
Return on Net Fixed Assets 6% 3% 6% 5%
BPA averaged a RONFA of 5.5 percent between 2018 and 2019. BPA’s balance sheet has been steadily
improving on key indicators since 2016 with the GR consistently decreasing because of the reduction in
BPA’s total debt. Similarly, with a steadily improving CR, BPA can cover its short-term obligations relatively
reliably. BPA’s return on average equity is currently better than that of VRA.
All the indicators point to BPA being in a healthy position to attract financing or contract debt for
generation projects.
6.2 ECG’s Key Risks and Other Considerations
Key risks to ECG’s creditworthiness come in the form of internal and external risks. The primary internal
risk is ECG’s own operational performance, especially as measured through total losses—technical,
commercial, and collection. The external risk exposures of ECG include state bill payments, PURC tariff
setting, and related currency and fuel price risks.
Operational Performance
ECG distributes 64 percent or about two-thirds of the energy in Ghana’s electricity market, making it the
most significant source of revenue for the power system’s value chain. This is especially true because
Ghana’s second largest distribution utility—NEDCo—does not have any formal PPA obligations and
operates in the relatively less consumer dense parts of the country. ECG’s operational performance,
especially as gauged through the lens of total losses (technical, commercial, and collection) is particularly
impactful on the financial health of the greater power sector. ECG is reported to be operating with
aggregate technical and commercial (AT&C) losses of 24.7 percent and 26.2 percent in 2019 and 2020,
respectively, which are generally considered to be excessive. This is a source of concern.
State Bill Payments
The agencies of the GoG are a significant customer group for ECG. Delays or arrears in payment for
electricity supplies to state premises have a significant impact on ECG’s cash flow and performance. In
recent years and as admitted in the Energy Sector Recovery Plan, the GoG has recognized that the state
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agencies have been a significant contributor to ECG’s arrears and is taking steps toward closing this gap.
Until the payment discipline of this group is seen to have improved, this will continue to be perceived as
a risk to the financial health of energy sector actors.
PURC Tariff Setting and Related Risks
Over the years, ECG and other sector actors, including NEDCo, VRA, and GRIDCo, have complained about
the PURC’s tariff setting. As the only mandated institution responsible for tariff setting for the regulated
market, the utilities submit their tariff proposals for consideration by the PURC, which has the final say on
tariffs awarded.
In 2021, ECG submitted tariff proposals requesting an increase in their distribution service charges (DSCs)
based primarily on increasing costs of operation and exchange rate changes. The PURC granted no
increment on ECG’s DSCs. If the increase request is truly reflective of full cost recovery as claimed by the
utilities, then the failure to grant the increase would represent a significant impact on the financial
sustainability of ECG.
Similarly, VRA, NEDCo, and GRIDCo, during the same tariff review period, submitted tariff proposals for
increments which were also denied. The level of tariff and tariff setting practices are therefore likely to be
considered a risk factor by potential lenders to the sector.
Related Risks
The PURC’s tariff setting process and decision-making have a knock-on effect on the ability of the utilities
to consistently deal with changes in their costs of service delivery. The volatility of currency exchange
rates and fuel costs are risks that are typically passed on to the offtakers as part of their contractual
obligations toward generators (especially IPPs) and, by association, fuel suppliers. Between October 2021
and April 2022, the Ghanaian cedi to US dollar exchange rate went from 6.05 to 7.5 (peaking above 8 in
mid-March) while electricity tariffs remained stagnant in nominal local currency terms. During the same
period, the price of crude oil also changed from US$86/bbl to US$104/bbl. With no change in the approved
tariffs chargeable by ECG, which are denominated in local currency, the weakening currency, and
increasing fuel prices, it understandably becomes more difficult for ECG to meet its obligations to
upstream electricity value chain service providers whose costs and payments are largely denominated in
foreign currency.
6.3 Generators’ Key Risks and Other Considerations
This section discusses several key risks (internal and external) and other considerations relevant to the
financial positions of VRA and BPA that are key determinants of their financial performance and,
therefore, creditworthiness.
Organizational and Power Generation Portfolio Performance
VRA and BPA are both growing utilities which are increasing their breadth of power generation projects.
VRA’s current power generation portfolio has a total of 11 power generation facilities: 2 hydropower, 6
thermal, and 3 solar PV. Similarly, BPA’s current power generation portfolio includes hydropower and
solar PV generation facilities. The two organizations have ambitions to add to their power generation
portfolio.
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Whereas the PPAs of private IPPs have capacity as well as energy charges, the contractual arrangements
of both VRA and BPA with ECG only have energy charge and so these utilities get paid only for electricity
generated. The financial performance and fortunes of these utilities are even more closely tied to the
dispatch and operation of their power generation portfolio than, for example, private thermal power
generators. The underperformance of any of these power generation projects poses a risk to their
financial stability and profitability.
It must be noted that, in recent years, some plants in VRA’s generation portfolio have experienced some
unexpected occurrences whose end result has been a reduction in output and, therefore,
underperformance. This is damaging to the utility’s finances, especially because some of these
underperforming assets have ongoing liabilities associated with them. The Takoradi 1 Thermal Plant (T1),
for instance, has experienced operational issues with its second gas turbine. Additionally, the entire
Takoradi Thermal Complex had been experiencing issues with cooling systems, which resulted in rationing
of operations at the complex. Finally, in 2013, the 132 MW Takoradi 3 Thermal Plant experienced a major
incident which has resulted in the cessation of generation from that plant since then.
ECG Performance and Payments
As noted elsewhere in this report, both VRA and BPA are highly exposed to their primary offtaker ECG.
Currently, ECG is BPA’s only offtaker. Therefore, any shortfall in ECG’s payments to BPA has a major
negative effect on BPA’s finances. Similarly, ECG consumes more than 40 percent of VRA’s annual
generation. According to VRA’s 2020 Annual Statements, VRA had outstanding receivables of GHS 1,949
million (equivalent to US$322 million) from ECG. Therefore, ECG is a significant source of revenue and a
corresponding financial performance risk for VRA as well.
Finally, the consultant understands that after years of discussions, a cash waterfall mechanism was
implemented to harmonize the sharing of ECG-gathered revenues with participants in the electricity value
chain (including VRA, BPA, GRIDCo, and fuel suppliers).
PURC Tariff Setting
As discussed previously, the VRA submitted tariff proposals in 2021 seeking an 18 percent increase in their
bulk generation tariff (BGT) based primarily on increasing fuel prices and exchange rate changes. The PURC
granted no increment on the BGT which is the rate paid for energy supplied by VRA to ECG. If any part of
the increase requested was truly reflective of full cost recovery, then the failure to grant the increase
would represent a significant impact on the financial sustainability of VRA.
Similarly, ECG, NEDCo, and GRIDCo, during the same tariff review period, submitted tariff proposals for
increments which were also denied by the PURC.
The PURC indicated that it had recognized an over-recovery of revenue after reconciliation of data on
hydroelectrical generation by VRA. In addition to the approval of 64 percent hydro-allocation by the
Electricity Market Oversight Panel to the regulated market, there was, in the view of the PURC, a marginal
reduction of cost of procuring power from VRA by the distribution companies. The PURC had, therefore,
decided that the distribution companies should be allowed to use this revenue to address revenue
shortfall challenges relating to power sales to industrial customers.
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Fuel Costs and Availability
Related to the PURC tariff setting risks affecting VRA, the authority, especially without the necessary
adjustments in tariffs, is exposed to variations in fuel costs driven by fuel mix and global price changes. In
2021, VRA generated about 40 percent of its annual electricity output from thermal sources. These
thermal generators are fueled primarily by indigenous natural gas and imported liquid fuels. When recent
liquid fuel import price changes are paired with Ghana’s recent currency depreciation, it can be
understood that VRA’s financial situation is significantly weakened by the denial of BGT increases.
6.4 Other Considerations – GRIDCo Operations
As Ghana’s sole ETU, GRIDCo is the bridge between the operations of generators and distributors and/or
bulk consumers. GRIDCo’s technical performance has a significant bearing on the operations of both
generators and the distribution utility. If the NITS is not operational, both generators (especially VRA and
BPA) and distributors who rely on the NITS for their operations suffer revenue losses.
Additionally, if GRIDCo’s operations are suboptimal, the effect on ECG’s operations, especially given
previously discussed tariff setting issues, results in reductions in ECG revenues, which further strains
payments for the rest of the upstream electricity value chain.
6.5 Assessment of Fundraising and Financing Options
ECG
Of the three utilities considered for this assignment, ECG is the least creditworthy. Within the context of
ECG’s mandate, ECG’s financial strength needs to be reviewed with long-term liabilities as the primary
focus. ECG’s negative DSCR and often negative RONFA would be a significant cause for concern to lenders.
The impact of this relatively poor performance is also evidenced by the approach of multiple project
developers to require state guarantees in support of ECG’s purchase obligations.
ECG’s exposure to currency risk through the PURC tariff setting’s potential shortcomings is also likely to
provide a cause for concern about erosion of ECG’s finances from any depreciation of the local currency
against major global currencies.
VRA
VRA is a relatively creditworthy organization when viewed through the lens of short-term lending
indicators such as the CR. Therefore, the VRA should be able to access short-term debt funding for
operational costs.
However, VRA performs sub-optimally on the primary long-term lending indicators such as DSCR. As DSCR
is a key indicator of the long-term creditworthiness and performance of the offtaker, VRA’s ability to
obtain funding for power generation projects from financing institutions (on development finance
institution [DFI], blended, or commercial finance bases, as discussed in Section 0 below) is hampered by
its DSCR indicator levels.
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BPA
BPA is the most creditworthy of the three utilities considered under this assignment. BPA scores well on
multiple indicators of creditworthiness for both short- and long-term lending. As noted earlier, however,
a related secondary concern is with the creditworthiness of an offtaker such as ECG. So alternative
offtakers may be considered a more acceptable proposition for lenders.
6.6 Summary of Market Debt Finance Options for Solar PV Projects
Beyond concessional financing such as that provided by KfW for multiple VRA solar PV projects in Ghana,
there are three primary types of financing available to fund solar PV projects:
• Development financing, which is typically provided by a DFI such as the World Bank, FMO,
Norwegian Investment Fund for Developing Countries (Norfund), and so on
• Commercial financing, which is typically provided by a commercial bank
• Blended finance, a combination of commercial and development financing, as has been offered
by Chinese entities of late and typically achieved by obtaining funding from multiple institutions
fitting the lending type.
A summary of the typical terms associated with each of these funding types is presented in Table 21.
Table 21: Summary of Debt Financing Options and Terms
Item DFI Blended Commercial
Debt Proportion 70% 70% 70%
Interest Rate 5% 8% 10
Term 15 10 5
Grace Period 1 1 1
For this assignment, the cost of equity was assumed to be 18 percent.
6.7 Generation Cost Impact of Achieving the 10 Percent RE Target
To assess the generation cost impact of reaching the 10 percent RE target, the consultant analyzed
multiple configurations of project module size and implementation approaches by comparing the
resulting LCOE for the various solar PV project simulations against the composite bulk generation tariff
(CBGT).
Composite Bulk Generation Tariff
For this assignment, the consultant used the PURC’s gazette CBGT for January 2022. The CBGT published
was GHS 44.1224/kWh which is equivalent to US$0.073/kWh, using exchange rate of 6.05 as at the date
issued.
LCOE for New Solar PV Projects
Based on the project module costs shown in Table 9 and the identified debt funding options shown in
Table 21, the consultant analyzed the LCOE (in US$/kWh) for each solar PV project implementation
scenario in either basic or comparable financial configurations. Table 22 shows the results of this analysis.
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Table 22: Solar PV Project LCOE Summary of Results
Implementation Scenario LCOE Results ($/kWh)
Financing Scenario
20 Basic 20 Comp 50 Basic 50 Comp 100 Basic 100 Comp
DFI 0.0640 0.0653 0.0590 0.0674 0.0588 0.0669
Blended 0.0729 0.0860 0.0670 0.0768 0.0667 0.0762
Commercial 0.0789 0.0935 0.0725 0.0833 0.0722 0.0826
As expected, the results in Table 22 show that lower-cost financing results in a lower cost of electricity
supply; therefore, DFI financing is more capital efficient than blended and commercial financing in that
order. Also, as expected, the basic configurations of solar PV projects, which present opportunities for
cheaper project capital expenditures (CAPEX), result in lower cost of electricity supply than the
comparable configurations. Therefore, depending on the project implementation configuration and
module sizes chosen, solar projects deployed under the scenarios discussed will be at LCOE levels between
US¢5.88/kWh and US¢9.34/kWh
Cost Impact of New Solar PV Projects
The LCOE results in Table 22 show that solar projects deployed under the scenarios discussed will be at
LCOE levels between US¢5.88/kWh and US¢9.34/kWh. The consultant evaluated the cost impact of new
solar PV projects between US¢5.5/kWh and US¢9.5/kWh and at US¢1/kWh intervals.
The results of the cost impact analysis, in Table 23, indicate that the new solar PV plants at price points
below US$0.073/kWh generate savings for the Ghanaian power system’s generation cost. These results
also indicate, as expected, that
1. The new solar PV projects are the least cost when implemented in larger modules and
2. The new solar PV projects generate the greatest savings impact with access to lower-cost, longer-
tenure financing such as DFI financing.
Table 23: Cost Impact of New Solar Plants
RE LCOE Scenarios ($/kWh)
Item 0.055 0.065 0.075 0.085 0.095
Composite Bulk Generation Tariff (GHS/kWh) 0.073 0.073 0.073 0.073 0.073
Total Demand (GWh) 35,772 35,772 35,772 35,772 35,772
Conventional Generation (GWh) 32,358 32,358 32,358 32,358 32,358
Total Cost of Conventional Generation ($'
2,360 2,360 2,360 2,360 2,360
millions)
RE Generation Gap Filled 100% 100% 100% 100% 100%
New RE Generation (GWh) 3,415 3,415 3,415 3,415 3,415
LCOE or RE Tariff ($/kWh) 0.055 0.065 0.075 0.085 0.095
Total Cost of New RE Generation ($' millions) 188 222 256 290 324
Average Generation Tariff ($/kWh) 0.071 0.072 0.073 0.074 0.075
Change in Average Generation Tariff (%) -2.35% -1.04% 0.27% 1.58% 2.89%
Annual Savings on Generation ($' millions) 61.23 27.08 (7.07) (41.22) (75.37)
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7 Conclusions and Recommendations
This section presents key takeaways or conclusions from the various subjects considered in the report.
7.1 Project Financing Structures of Existing Solar Projects
There are six existing solar projects:
• VRA’s 2.5 MW Navrongo Solar Plant
• BXC’s 20 MW Solar Plant
• Meinergy’s 20 MW Solar Plant
• VRA’s 17 MW Kaleo Solar Plant
• BPA’s 50 MW Solar Plant
• VRA’s 6.5 MW Lawra Solar Plant.
Table 24: Summary of Existing and ‘Under-Construction’ Solar PV Projects' Financing Information
First Year
Funding Primary Funding
RE Projects of Funding Terms
Agency Type
Operation
VRA Solar 1 - Navrongo 2013 VRA VRA Equity Only
- Interest Rate = 1%
VRA Solar 2 - Kaleo 2020
- Grace Period = 7 Years
KfW Concessional Loan
- Repayment Term = 40 Years
VRA Solar 3 - Lawra 2023
- Debt Ratio = 80%
BXC 2016 China N/A N/A
Meinergy 2018 Export N/A N/A
Bui Solar Farm 1 2021 Credit N/A N/A
Table 25: Summary of Existing and ‘nder-Construction’ Solar PV Projects' Commercial and Performance
Information
Expected Equiv. Tariff
Capacity Solar Yield Tariffs First Year of Tariffs
RE Projects Energy (Base Year =
(MW) (MWh/MW) (US$/kWh) Operation (US$/kWh)
(GWh) 2020)
VRA Solar 1 - Navrongo 2.5 3 1200 0.1725 2013 0.1725 0.0761
VRA Solar 2 - Kaleo 17 26.6 1565 0.0950 2020 0.0950 0.0950
VRA Solar 3 - Lawra 6.5 10 1565 0.0900 2023 0.0900 0.0910
BXC 20 27 1350 0.2014 2016 0.2014 0.1237
Meinergy 20 27 1350 0.1825 2018 0.1825 0.1588
Bui Solar Farm 1 50 68 1360 0.1024 2021 0.1024 0.1024
Total RE Generation (GWh) 116 162
These projects were implemented over 10 years (2013–2022). During this period, the global
implementation costs for fixed tilt solar PV projects dropped by over 80 percent (as shown in Figure 6).
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Therefore, the LCOEs of the different projects executed do not provide an accurate comparison of the
projects’ financial efficiency.
VRA’s Navrongo Solar Plant was funded by VRA equity only. The BXC, Meinergy, and BPA projects were
financed using China Export Credit. The VRA Solar Plants at Kaleo and Lawra were funded by concessional
loans from KfW.
The BXC and Meinergy plants were executed during the REFiT regime and at higher tariffs that provide
cash flows significant enough to absorb any additional costs to the project, especially from land
acquisition.
With the BXC and Meinergy being the only privately owned solar PV plants, the remaining solar projects
benefit from nonmarket-based lending structures (in the form of concessional loans) as well as statutory
and infrastructure advantages presented by the sponsoring state institutions—VRA and BPA.
7.2 Economic and Financial Analysis
Creditworthiness
As the largest distribution company in Ghana, ECG’s performance is a significant determinant of the
Ghanaian power sector’s overall financial position. As evident from requirements for GoG guarantees for
electricity supply projects in the recent past, ECG is not viewed as a creditworthy entity for long-term
power supply to be funded using project finance structures.
The creditworthiness of the generators (BPA and VRA) is largely considered on a project-by-project basis
and focuses on the viability and creditworthiness of the project’s offtaker, rather than the generators
themselves, unless they are intermediary offtakers which has been the case for BPA’s existing 50 MW
Solar Project and the VRA’s Takoradi 2 Thermal Project. In cases where these generators act as
intermediary offtakers, their creditworthiness is determined through the strength of their own balance
sheets as well as those of the eventual offtaker—typically a distribution utility or bulk consumer.
Currently, BPA is a more creditworthy entity than VRA.
Risks and Other Considerations
The primary risk exposures affecting ECG’s creditworthiness in terms of assuring its providers of full and
regular payments are
• Its own operational performance especially in terms of aggregate technical, commercial, and
collection (ATC&C) losses;
• Volatility of exchange rates and fuel costs;
• GoG payments of electricity bills on behalf of SOEs and facilities;
• GRIDCo’s and generators’ operations; and
• The PURC’s tariff setting processes.
BPA and VRA are both highly exposed to ECG. A summary of their other risks includes
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• Organizational and power generation portfolio performance,
• Fuel availability and costs,
• ECG performance and payments,
• PURC tariff setting, and
• GRIDCo operations.
7.3 Mandates and Responsibilities for Supply to Regulated and Deregulated Markets
The following were the key conclusions from the report regarding utility mandates:
• None of the utilities (ECG, BPA, and VRA) have any obligations toward the deregulated market.
• ECG is only responsible for electricity procurement for the regulated market customers in those
geographic areas for which it holds the distribution concession.
• BPA and VRA have mandates for electricity generation functions but with no explicit obligations
to take responsibility for supplying customers in the regulated nor deregulated markets.
Table 26: Summary of Utilities' Mandates and Creditworthiness
Utilities
Electricity Company Volta River Authority Bui Power Authority
Criteria
of Ghana (ECG) (VRA) (BPA)
Mandate Obligation Mandate Obligation Mandate Obligation
Power Generation No No Yes Voluntary Yes Voluntary
Electricity Procurement or Supply (Regulated Market) Yes Yes Yes Voluntary Yes Voluntary
Electricity Procurement or Supply (Deregulated Market) No No Yes Voluntary Yes Voluntary
Solar PV Project Implementation Experience N/A 26 MW 50 MW
Future Solar PV Implementation or Procurement Plans N/A 60 MW 160 MW
Stable & Trending Stable & Trending Positive & Trending
Financial Situation & Trend
Upward Stable Upwards
7.4 Solar PV Procurement Plans and Investments to Reach 10 Percent RE Commitment
The following were the key takeaways from the consideration of power sector procurement plans and
RE commitments:
• ECG has no explicit power procurement plans for the next five years; the company expects that
the current situation of overcapacity will end in 2028–2030.
• In the next five years, the utilities (BPA and VRA) will work toward the following notable solar PV
project plans:
o BPA has signed contracts and is actively seeking funding to implement two solar PV projects
totaling 150 MW.
o VRA is developing the 60 MW Bongo solar PV plant.
• The Ghanaian power system’s electricity demand and energy demand are expected to reach over
5,588 MW and 35,772 GWh in 2030.
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• To meet a 10 percent RE target with solar PV generation, approximately 2,511 MW of new solar
PV generation will be required to generate approximately 3,415 GWh annually.
• Depending on the project module sizes of 20, 50, and 100 MW, the Ghanaian power system will
require 122, 49, and 25 MW modules, respectively.
• The general deployment strategy could be to use the 20 MW module when the plant is to be
connected to the distributions network and the 50 MW and 100 MW modules for the cases where
the generation would be evacuated through a NITS node.
• Depending on the project configurations, the projects are expected to require US$1,615–2,243
million.
Table 27: Summary of Solar PV Project LCOE and Investment Requirements to Reach 10 Percent RE Target
Cost Category & Item 20 MW 50 MW 100 MW
Engineering, Procurement, & Construction (A) $ 14,319,885 $ 32,319,885 $ 64,319,885
Project Preparation (B) $ 3,149,935 $ 5,929,870 $ 11,489,740
Statutory Approvals (Permitting & Licensing) (C ) $ 40,000 $ 40,000 $ 40,000
Solar Plant Basic Solar Plant Costs (A) $ 14,319,885 $ 32,319,885 $ 64,319,885
Costs Comparable Solar Plant Costs (A + B + C) $ 17,509,820 $ 38,289,755 $ 75,849,625
Calculated Basic Solar Plant Costs ($/kW) $ 716 $ 646 $ 643
Benchmarks Comparable Solar Plant Costs ($/kW) $ 875 $ 766 $ 758
Project Configuration Basic Comp Basic Comp Basic Comp
LCOE by DFI 0.0640 0.0653 0.0590 0.0674 0.0588 0.0669
Financing Blended 0.0729 0.0860 0.0670 0.0768 0.0667 0.0762
Scenario Commercial 0.0789 0.0935 0.0725 0.0833 0.0722 0.0826
Number of Projects to reach RE Target 126 51 26
Total Solar Project Only Cost (in $ 'millions) $ 1,843 $ 2,244 $ 1,623 $ 1,923 $ 1,615 $ 1,905
Transmission Upgrade Cost $ 473
Total Cost (in $ 'millions) $ 2,316 $ 2,716 $ 2,096 $ 2,396 $ 2,088 $ 2,378
• To implement solar PV projects sufficient for reaching the RE target, the NITS will require
reinforcement in key spots. The exact scope and extent of the transmission projects depend on
project location, project size, system load distribution, and NITS’ performance at the time of
implementation.
• It is estimated that a total investment of approximately US$473 million will be required for various
NITS reinforcement projects intended to help resolve any challenges with transfer capacity and
grid stability arising from the implementation of the solar PV projects.
7.5 Recommendations
Based on the analyses and observations contained in this report, the following recommendations are
made:
• Solar PV projects should be implemented at the largest possible single module scale to improve
the cost efficiency and savings to the power system.
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• To facilitate improved tariff offers, solar PV projects should be competitively procured with
provision of enabling services (such as intermittency mitigation and ancillary services) and land
commonly provided to all bidders on the same terms. The procured solar PV project sites should
be acquired by state agencies to minimize the cost of land acquisition. GRIDCo should be included
as part of the stakeholders to identify suitable sites for large-scale solar PV projects as the cost-
efficient evacuation infrastructure will be critical for efficient implementation.
• The solar PV projects should be implemented in the largest possible single module sizes and
paired with competitive procurement to achieve the lowest LCOE possible for the particular
financing arrangement.
• Regarding project deployment strategy, the smaller project modules, such as the 20 MW module,
should be used to feed directly to local distribution networks, where viable. The larger project
modules, for example, 50 MW and above, should then be deployed in cases where the generation
would be evacuated through the Ghanaian NITS.
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References
• Integrated Power System Master Plan
• Strategic National Energy Plan 2030, July 2019
• Renewable Energy Master Plan, February 2019
• Accra Climate Action Plan – Five-Year Plan (2020–2025)
• Ghana’s Updated Nationally Determined Contribution under the Paris Agreement (2020–2030),
November 2021
• 2021 Electricity Supply Plan
• 2021 Energy Outlook
• Competitive Procurement Policy for Electricity and Fuel, May 2019
• Energy Sector Recovery Program, May 2019
• PURC Gazetted Tariffs, January 2021
• Ghana Grid Code
• VRA’s 2021 Tariff Proposals
o VRA
o ECG
o GRIDCo
• Utilities’ Annual Performance Statements
o ECG
o VRA
o BPA
o GRIDCo
• NREL ‘Documenting a Decade of Cost Declines for PV Systems’ -
https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-
systems.html
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