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ASSESSMENT OF A PUBLIC PRIVATE
PARTNERSHIP TO BUILD, OWN AND
OPERATE A PORTFOLIO OF SOLAR PV
PLANTS ON MUNICIPAL RESERVOIRS IN
ETHEKWINI METRO MUNICIPALITY.
FEASIBILITY STUDY FINAL REPORT
OCTOBER 2019
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Chemonics International for USAID/South Africa (2019) Assessment of a Public Private Partnership to Build, Own and
Operate a Portfolio of Solar PV Plants on Municipal Reservoirs in eThekwini Metro Municipality: Feasibility Study Report.
For the USAID South Africa Low Emissions Development Program.
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DISCLAIMER:
The author’s views expressed in this publication do not necessarily reflect the views of the United States Agency for
International Development or the United States Government.
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Contents
1 INTRODUCTION .......................................................................................................................... 23
1.1 PROJECT BACKGROUND AND REPORT OBJECTIVES ................................................................................. 23
2 NEEDS ANALYSIS ........................................................................................................................ 27
2.1 MUNICIPALITY’S STRATEGIC OBJECTIVES .................................................................................................. 27
2.2 GREENHOUSE GAS REDUCTION AND CLIMATE CHANGE MITIGATION ..................................................... 29
2.3 BUDGET ................................................................................................................................................ 30
2.4 INSTITUTIONAL ANALYSIS ...................................................................................................................... 32
2.5 OUTPUT SPECIFICATIONS ....................................................................................................................... 32
2.6 PROJECT DEFINITION ............................................................................................................................. 35
3 TECHNICAL SOLUTION OPTIONS ANALYSIS .................................................................... 37
3.2 EVALUATION OF THE PREFERRED TECHNICAL OPTION ............................................................................ 39
3.3 KEY PARAMETERS FOR FINANCIAL ANALYSIS ........................................................................................... 45
4 PROJECT DUE DILIGENCE ......................................................................................................... 57
4.1 LEGAL ASPECTS ...................................................................................................................................... 57
4.2 USE RIGHTS AND SITE ENABLEMENT ....................................................................................................... 69
4.3 SOCIO-ECONOMIC AND BBBEE ............................................................................................................. 71
4.4 ACCURACY OF MEASUREMENTS AND RECORDINGS IN FEASIBILITY STUDY ................................................. 72
4.5 GENERAL DUE DILIGENCE CONSIDERATIONS ......................................................................................... 72
5 SERVICE DELIVERY ANALYSIS ................................................................................................. 76
5.1 PROPOSED PPP TYPE ............................................................................................................................. 77
5.2 INSTITUTIONAL CAPACITY ..................................................................................................................... 78
6 VALUE ASSESSMENT .................................................................................................................. 80
6.1 AFFORDABILITY ..................................................................................................................................... 80
6.2 VALUE FOR MONEY ............................................................................................................................... 83
6.3 RISK ASSESSMENT AND RISK TRANSFER ................................................................................................... 87
6.4 SUMMARY.............................................................................................................................................. 93
7 PROCUREMENT PLAN ................................................................................................................ 96
7.1 MARKET CAPABILITY AND APPETITE ........................................................................................................ 96
7.2 PPP PROCUREMENT ............................................................................................................................... 97
7.3 MUNICIPAL PPP PROCESS COMPLIANCE ................................................................................................. 98
8 APPENDICES ............................................................................................................................... 103
APPENDIX 1: LAND DUE DILIGENCE REPORT .................................................................................................. 103
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List of Figures
FIGURE 1. EKURHULENI 200KW SOLAR PV PROJECT AT THE OR TAMBO PRECINCT, WATTVILLE .............................. 39
FIGURE 2. SIMULATION RESULTS OF DC CAPACITY AND EXPECTED ENERGY YIELD PER RESERVOIR SITE ..................... 45
FIGURE 3. CONSTRUCTION COST BREAKDOWN ...................................................................................................... 48
FIGURE 4. PV PLANT CAPACITY VS NPV FOR EACH RESERVOIR SITE .......................................................................... 50
FIGURE 5. EXAMPLE: SENSITIVITY OF EQUITY IRR TO FUTURE TARIFF ESCALATION .................................................... 53
FIGURE 6. EXAMPLE: SENSITIVITY OF EQUITY IRR TO CAPITAL COSTS ....................................................................... 53
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List of Tables
TABLE 1. EXTRACT FROM ETHEKWINI COUNCIL AUTHORISATION ON ELECTRICITY PPAS ......................................... 29
TABLE 2. EXPECTED GREENHOUSE GAS REDUCTIONS FROM THE PROJECT ................................................................ 29
TABLE 3. 2018/2019 MUNICIPAL EXPENDITURE ON EQUIVALENT POWER PURCHASES (AT 4.6MWP – LOW CASE) ..... 30
TABLE 4. 2018/2019 MUNICIPAL EXPENDITURE ON EQUIVALENT ELECTRICITY PURCHASES (AT 9.8MW – HIGH CASE)30
TABLE 5. MUNICIPAL EXPENDITURE ON EQUIVALENT ELECTRICITY PURCHASES 2019 – 2021 INDEXED (R / YR) .......... 31
TABLE 6. KEY SERVICE INTERFACES .......................................................................................................................... 34
TABLE 7. TECHNICAL OPTIONS EVALUATION .......................................................................................................... 37
TABLE 8. PROJECT PORTFOLIO – INSTALLATION CAPACITY AND YIELD PER RESERVOIR SITE ...................................... 44
TABLE 9. WEIGHTED AVERAGE TARIFF FOR SOLAR PV .............................................................................................. 46
TABLE 10. ESKOM AVERAGE PRICE INCREASE PATH .................................................................................................... 47
TABLE 11. SUMMARY OF INITIAL NPV RESULTS......................................................................................................... 49
TABLE 12. KEY PROJECT FINANCE MODEL ASSUMPTIONS ......................................................................................... 51
TABLE 13. ESTIMATED ROOFTOP RETAIL PV MARKET SIZE ........................................................................................ 54
TABLE 14. EVALUATION OF ACTIVITIES AGAINST NEMA BASIC ASSESSMENT ACTIVITIES LIST ..................................... 63
TABLE 15. SITE CONDITION REQUIREMENTS AND CONSIDERATIONS OF ALLOCATION OF RESPONSIBILITY ................ 70
TABLE 16. NATIONAL TREASURY DESIGNATED SECTORS INSTRUCTION FOR LOCAL PRODUCTION AND CONTENT FOR
SOLAR PV ..................................................................................................................................................... 71
TABLE 17. DUE DILIGENCE AND RISK TRANSFER CONSIDERATIONS ............................................................................ 72
TABLE 18. SERVICE DELIVERY ANALYSIS ..................................................................................................................... 76
TABLE 19. VALUE FOR MONEY DRIVERS .................................................................................................................... 84
TABLE 20. INDICATIVE NPV OF PROJECT LOW CASE COMPARED TO CURRENT PRACTICE .......................................... 85
TABLE 21. RISK ASSESSMENT AND TRANSFER ............................................................................................................. 87
TABLE 22: PPP PROCUREMENT POTENTIAL RISKS AND MITIGATION PLAN ............................................................................ 98
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List of Abbreviations
AC Alternating Current
CSIR Council for Scientific and Industrial Research
COGTA Department of Cooperative Governance and Traditional Affairs
CPG Contract Participation Goals
DC Direct Current
DOE Department of Energy
EIA Environmental Impact Assessment
ERA Electricity Regulation Act 4 of 2006
EWS eThekwini Water and Sanitation
GHG Greenhouse Gas
HAS Hazardous Substances Act
IRR Internal Rate of Return
KNCA Kwa-Zulu Nature Conservation Act
KNCMA Kwa-Zulu Natal Nature Conservation Management Act
KZNHA Kwa-Zulu Natal Heritage Act
kW Kilowatt (Alternating Current (“AC”) capacity equivalent to net capacity
kWh Kilowatt Hours
kWp Kilowatt Peak (Direct Current (“DC”) capacity equivalent to gross capacity
MFMA Municipal Finance Management Act No. 56 of 2003
MPRDA Mineral and Petroleum Resources Development Act
MSA Municipal Systems Act
MTREF Medium Term Revenue and Expenditure Framework
MW Megawatt
MWh Megawatt Hours
MWp Megawatt Peak
NBR & BSA National Building Regulations and Building Standards Act
NCO Nature Conservation Ordinance
NEMA the National Environmental Management Act No. 107 of 1998
NEM : AQA National Environmental Air Quality Act
NEM: BA National Environmental Biodiversity Act
NEM : ICMA National Environmental Management Integrated Coastal Management Act
NEM: PAA National Environmental Management Protected Areas Act
NEM: WA National Environmental Management Waste Areas Act
NFA National Forest Act
NERSA National Energy Regulator of South Africa
NHRA National Heritage Resources Act
NPV Net Present Value
NWA National Water Act
PPA Power Purchase Agreement
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PPP PARTNER Independent Power Producer
PV Photovoltaic
REIPPPP Renewable Energy Independent Power Producers Procurement Programme
SALA Subdivision of Agricultural Land Act
SA-LED USAID/ South African Low Emissions Development Programme
SAPVIA South African Photovoltaic Industry Association
SCM Supply Chain Management
SPLUMA Spatial Planning and Land Use Management Act
WSA Water Services Act
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EXECUTIVE SUMMARY
The eThekwini Municipality (“the Municipality”) has the constitutional responsibility to
provide social amenities, services and infrastructure to residents across eThekwini. Through
its water and sanitation unit, eThekwini Water and Sanitation (“EWS”), it provides water and
sanitation services to all residents. In undertaking this responsibility EWS owns and operates
a large number of water reservoir sites around the city.
These reservoir sites offer unused land within the city that can be utilised for other activities,
such as the siting of solar photovoltaic (“PV”) plants. The Municipality also has strategic
objectives under its Integrated Development Plan, Durban Climate Change Strategy and
Energy Strategy which support the introduction of renewable energy into the energy supply
mix of the Municipality.
The Municipality intends to decide on entering into a long-term contract of up to 20 years
with a private partner to finance, build, own and operate a portfolio of solar PV plants on the
municipal reservoir assets (“the Project”). Therefore, the Municipality requires the necessary
technical, legal, and financial information, to be able to make a well-founded decision relating
to the procurement of a public private partnership (“PPP”) or an alternative contractual
arrangement for the Project. A feasibility study is one of the essential elements in order to
reach this objective.
This feasibility study is aimed at evaluating whether renewable electricity can be generated in
a safe and reliable manner at a competitive price compared with alternative electricity supply
options. The feasibility study is also aimed at further technical evaluation of the PV plants
including the optimal size of the plants per site, forecast generation and siting considerations.
The evaluation also includes an identification of the requirements for connection into the
municipal electricity distribution grid as well as other factors to be considered prior to a
procurement decision and final design of the Project. This includes the determination of
associated costs (investment and operational), the Project’s economic viability and an
indication of the procurement process to be followed.
The Municipality has requested the USAID-funded, South Africa Low Emissions Development
Programme (“SA-LED”), to assist in the preparation of the feasibility study as one of the steps
towards the implementation of a PPP project. As part of the PPP process the study will
provide information to the eThekwini Municipal Council, to National Treasury, relevant
organs of state and the public regarding the investigation into the technical and procurement
options considered for the proposed solar PV generation portfolio. However, it must be
noted that SA-LED has not been appointed as a Transaction Advisor for the Project in terms
of the South African Regulations for PPPs. Therefore, the scope of the feasibility assessment
may not address in full all the requirements of the feasibility stage of a PPP project. Where
additional investigation or actions are required these have been identified as further actions
to be undertaken prior to a final decision to proceed and preparation of procurement
documentation.
The feasibility study has been performed and reported according to the following structure:
Section 1: provides an Executive Summary and an Introduction to the project
including a brief project motivation.
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Chapter 2: presents a Needs Analysis which provides more detail on the proposed
technical solution and outlines how the project aligns with the strategic objectives of
the Municipality. The needs analysis also encapsulates an analysis of the Municipality’s
current costs of electricity, demonstrates its commitment and capacity, and specifies
the outputs of the proposed project. This includes an overview of the data collection
approach, being both site visits and data sourcing from various departments of the
Municipality.
Chapter 3: specifies the Technical Solutions Options identified and considered, it
presents the modelling and electricity generation forecasts conducted. Based on this
a technical recommendation for a preferred option is indicated. The key parameters
for the financial evaluation are also indicated and, conclusions and recommendations
are formulated based on a combination of technical and financial considerations.
Chapter 4: provides a report on the Due Diligence Investigation executed
including legal, risk allocation, broad-based black economic empowerment (“BBBEE”)
and other socioeconomic issues.
Chapter 5: presents the Service Delivery Analysis which evaluates the relative
merits of the delivery of the project and considers the institutional capacity
requirements of the Municipality to manage the Project.
Chapter 6: presents the Value Assessment which considers the preferred option in
more detail and further consideration of technical, financial and institutional risk
factors.
Chapter 7: outlines a proposed Procurement Plan on how the project will be
procured within the confines of the MFMA, Supply Chain Management (“SCM”)
procedures and PPP regulations.
The key findings of the feasibility study are summarised below.
Needs analysis
The needs analysis draws information from secondary data, drawings, visual inspections,
discussions with the Municipal officials well as financial data. The critical findings of the study
are summarised below.
The primary goal of the Project is to utilise available land on EWS reservoir sites to produce
renewable energy generated by solar PV plants for export into the Municipal distribution grid.
The electricity will displace the purchase of electricity from the Eskom transmission grid,
thereby also reducing the Greenhouse Gas (“GHG”) emissions of power use in eThekwini,
promoting embedded renewable energy generation and starting to diversify sources of
electricity supply. At any tariff level below those of the Eskom bulk purchase tariffs there will
also be direct cost savings to the municipality.
The analysis identified that the Project would support a number of Municipal objectives
contained in the Municipal Integrated Development Plan, Durban Climate Change Strategy,
and the Municipality Energy Strategy. The project’s objectives are also supported by the
eThekwini Electricity Department Guidelines for Generators Connecting to the Grid (“the
Connection Guidelines”).
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The Project would reduce GHG’s through displacement of coal-based electricity. A total of
between 86 500 and 191 500 tCO2e would be reduced by the Project between 2019 and
2030. The project would therefore facilitate eThekwini Municipality’s ability to provide
continued electricity services to its citizens while reducing dependence on energy derived
from fossil fuels.
The Project can be implemented at various scales, with initial analysis suggesting a more likely
Low Case of 4.6 MW and a High Case of 9.8 MW. The expenditure per annum on power
purchases equivalent to those of the Project would be between R8.4 million and R16.3 million
respectively in the first project year. This therefore reflects the budget envelope available for
power purchases under the Project. The estimated budget allocations are approximately
0.07% and 0.13% of the total current budget for bulk electricity purchases.
Technical options analysis
The technical solution options analysis identified a range of options for meeting the required
objectives. The conventional and well proven option of ground-mounted solar PV with fixed
tilt mounting structures was selected as the preferred option which meets the Municipality’s
objectives, including the use of currently unused reservoir land.
The recommended scenario was based on the key design considerations of:
A minimum size of 100kWp as the lower size limit per installation to avoid sub-optimal
installations and to limit the portfolio to a manageable number of sites;
A maximum size of 1 000kWp as the upper size limit per installation to avoid the need
for a generation license in terms of current regulations;
The DC/AC ratio for all the simulations was in the range from 1.25:1 to 1.08:1. These
ranges can be further optimised depending on detailed design and final technology;
A key potential limitation per site is the available AC capacity of the nearest grid
connection. If the grid connection does not have enough capacity for the maximum
AC power produced by the inverters, then the design capacity will need to be reduced.
The eThekwini Municipality Electricity Department has confirmed that five out of the
seven selected sites in the Low Case can be connected to the local grid and can
evacuate the identified capacity i.e. Woodlands Tank 3 & 4, Montille 1 & 2, Dunkeld,
Umlazi 2 and Phoenix 2). Further assessments are being conducted on two of these
sites (Chatsworth 4 and Northdene).
Completing the installation of all possible 52 installations will result in a total installed peak
DC capacity of 9.8MW (“the High Case”). This is made up of 39 separate sites. Completing
the installation of only those installations with a positive net present value (“NPV”) at the
site level will result in a total installed peak DC capacity of 4.6MW (“the Low Case”). This is
made up of the seven largest sites in the portfolio, after one of the top eight sites was excluded
due to heritage concerns. The Low Case scenario is deemed the more realistic scenario as it
is the selection of sites most likely to be financially viable to a PPP partner under a PPP
arrangement.
As each site has a different grid connection cost each site will have a different capital cost and
hence a different return and financial viability. The Low Case scenario, used as the base case
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for the financial model, considers the seven sites as a combined project and hence spreads
the grid connection costs across the portfolio. If each site were to be considered separately
some sites, those where the grid costs are a smaller percentage of total capital costs, would
have greater financial viability.
The total capital cost for the selected projects would be approximately R53.1 million
excluding grid connection costs and R61.1 million with connection costs in included.
Operating costs have been assumed at 1.25% of capital costs per annum although it is noted
that there is some uncertainty around this value which is likely to only be made more certain
on receipt of project proposals from private partners.
Under the structure envisaged by the Municipality the full capital costs, including those for
grid connection, and the full operating costs would be borne by the PPP partner. The
associated model does, however, allow for a scenario under which the Municipality bears the
grid connection costs to allow this option to be considered.
It is important to note that final portfolio determination and hence the final total size of the
project can only be made following further technical, financial and risk assessment including:
Completion of the assessment and costing of local grid connections for all the sites
under consideration a preliminary grid assessment cost estimate has been provided by
the eThekwini Electricity Department and has been included in the analysis;
Final site filtering based on determined characteristics such as ground conditions,
security, shading and accessibility;
Ability of the private sector to meet the tariff benchmark, as the lower the private
sector tariff the greater the number of sites may become feasible for inclusion.
As the private sector bid tariffs cannot be known until the procurement process, it may also
be appropriate to design a procurement process that allows for some flexibility in the final
total project size as the scale has limited impact on the value for money assessment.
The envisaged technical solution is deemed technically feasible and therefore, with the above
caveats, it was determined that the solution could be pursued with the involvement of the
private sector and it was therefore subjected to further investigation as a candidate for a PPP.
Due diligence
The legal review took the form of a gap analysis, in order to determine:
The feasibility of procuring the services of a private partner through an agreement that
takes the form of a PPP;
Applications for additional licenses and/or authorisations that may be required, in
particular relating to the Electricity Regulation Act (“ERA”) and other regulations
governing the generation and sale of electricity;
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Whether the activities contemplated required an Environmental Impact Assessment
(“EIA”) and authorisation under the National Environmental Management Act No. 107
of 1998 (“NEMA”).
The legislative framework does appear to make provision for the use of a PPP in order to
execute embedded power generation by a PPP partner. The establishment of the Project as
a PPP will require adherence with the procedures as contained in the Municipal Finance
Management Act No. 56 of 2003 (“MFMA”) for the conclusion of a PPP agreement with a
private partner (the “PPP partner”).
Section 33 of the MFMA deals with contracts having future budgetary implications beyond the
three-year budget period of a municipality. As the structure of the Project would be to enter
into a PPA with a PPP partner over a 20-year period, or other lengthy period exceeding three
years, the PPA will be subject to approval in terms of Section 33.
The accounting officer may not sign a long-term PPP agreement unless section 33 of the
MFMA has been complied with.
Based on review of legislation it appears that the proposed Project activities are exempt from
the requirement to apply for and hold a licence under the Electricity Regulation Act 4 of 2006
(“ERA”). The act states that no person may, without a license issued by the National Energy
Regulator of South Africa (“NERSA”), operate any generation facility. However, exemptions
to this licensing were introduced in an amendment to the ERA which was issued under
Government Gazette No. 41237 of 10 November 2017. The effect was to amend Schedule 2
of the ERA which relates to exemptions of certain activities from having to obtain an
electricity generation licence. The Project meets the criteria of the Exemption under Section
2.1 of Schedule 2. There are further proposed amendments of the ERA Schedule 2 which
were published on 8 June 2018, however these are not yet promulgated into law and would
not affect the generation licensing requirements of the project.
Although a generation license is not required, registration of the systems with the National
Energy Regulator of South Africa (“NERSA”) is likely to be a requirement in terms of the
current draft government notice pertaining to licensing and registration of small scale and
embedded generators1. This registration process would need to be undertaken by either the
PPP partner or the municipality on behalf of the PPP partner once the project was
implemented.
SA-LED conducted an assessment to of whether the activities contemplated required an
Environmental Impact Assessment (“EIA”) and authorisation under the National
Environmental Management Act No. 107 of 1998 (“NEMA”). This assessment was mainly
informed by the Department of Environmental Affairs (2015) EIA Guideline for Renewable
Energy Projects and based on the assessment it appears that the Project may potentially
require an EIA, and that certain environmental risks may arise during the life-cycle of the
project. It is advised that the Municipality undertake a thorough assessment of any potential
environmental risks which may require an EIA, as well as develop an appropriate
1 Government Notice, no. 2018, Department of Energy, Electricity Regulation Act, 2006, Licensing Exemption and Registration Notice, Government Gazette, 13 May 2019, no. 424567. It is noted that this Notice is still in draft form and there may be changes in the final registration requirements once finally gazetted.
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environmental management plan for the entirety of the project as well as thereafter and in
relation to each of the individual sites. This can be achieved by the Municipality through co-
operative governance consultations with the KwaZulu-Natal Department of Economic
Development, Tourism and Environmental Affairs.
Despite the above review it is recommended that prior to starting the procurement process
for the Project confirmation from either internal or independent legal counsel is provided of
the above views on regulatory requirements and of whether other local or national regulatory
consents are required. A preliminary review of these matters has been provided via a legal
review conducted by Strauss Daly Attorneys.
Municipal capacity
Notwithstanding the strategic alignment of the project, it appears from the needs analysis that
the Municipality has limited technical capacity to implement the proposed Project itself and
to take long term responsibility for the operations and maintenance of the Project. It does,
however, have experience in managing a few alternative energy projects and has also carried
out the procurement of solar PV installations by external parties and is therefore able to
procure the Project through a municipal PPP and carry out the required monitoring and
contract management.
The project has been conceptualised and managed from EWS, as the manager of the reservoir
sites. However, EWS is collaborating with the eThekwini Electricity Department on the
financial and technical aspects of the project and it is expected that a joint approach will be
required to ensure a successful PPP process. It is therefore recommended that a project team
is established from these departments as well as potentially officials from the municipal finance
and supply chain management departments. The team should determine the allocation of
responsibilities for project oversight, performance monitoring and contract management and
preferably establish a simple document confirming this allocation.
The envisaged Project might also be an opportunity for technology and skills transfer to occur
from the private partner to the Municipal staff. There are also a few resources available to
assist municipal officials in solar PV procurement, including guidance provided by the Council
for Scientific and Industrial Research (CSIR) and other institutions.
Value assessment
All municipal PPPs governed by the Municipal PPP Regulations are subjected to three strict
tests:
Can the municipality afford the deal?
Is it a value-for-money solution?
Is substantial technical, operational and financial risk transferred to the PPP partner?
The simplified value assessment approach was adopted for the proposed project. No public
sector comparator was required as the alternative is not the construction of the Project by
the Municipality but rather a business-as-usual scenario of continued purchase of power from
Eskom. As such, only a simple PPP reference model was used which was a simple NPV and
Internal Rate of Return (“IRR”) analysis of the Project based on the replacement of a portion
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of current bulk power purchases with power purchases under a PPA from the Project, plus
the associated transaction and establishment costs of the Project borne by the municipality.
A base assumption, based on current municipal policy, is that the average cost of the power
supplied to the Municipality should not exceed the average tariff paid by the municipality for
electricity. The financial viability for the PPP partner was therefore calculated using the cost
of wholesale power for the Municipality, plus applicable local surcharges, as the upper bound
of the price to be paid for power under the Project PPA.
This tariff is based on a weighted average tariff applicable to the solar PV projects and was
estimated at 83.5c per kWh in 2018 at the time of the NPV analysis on a per site basis. For
the purposes of the evaluation of the project viability as a PPP a weighted average tariff of
R1.02 per kWh as a starting tariff in 2019/20 was used – the increase in the tariff resulting
from approved Eskom wholesale tariff increases since the start of the study.
Financial modelling using the same starting tariff results in an estimated Internal Rate of Return
“IRR” for the private sector party of approximately 12% to 18% nominal IRR over 20 years.
The returns are very sensitive to a number of assumptions such as the future price path of
the Eskom wholesale tariffs, whether the PPP partner bears the grid connection costs and so
forth. Given the IRR range it appears that a project attractive to a private partner could
possibly be implemented if suitable terms and allocation of risks and costs were established.
On the basis of the use of the tariff cap it was determined that the Municipality could afford
the Project as the cost of displaced power purchased would be less than or equal to the cost
of electricity that would otherwise be purchased from Eskom plus local distribution benefits.
There will, however, be transaction costs of procurement and possibly some grid connection
costs, depending on which party bears these costs, and prior to implementation the
Municipality should determine these costs and confirm their affordability and available budget.
It is anticipated that a land availability agreement or lease agreement would be entered with
the preferred provider at a nominal value and hence no revenue stream is expected from the
use of Municipal property. There is therefore no revenue stream from the Project to the
Municipality but rather the financial benefits arise from the avoided costs from bulk power
not purchased from Eskom. Of course, these benefits are balanced by the costs of the
payments paid to the private partner. No financial metric was placed on the economic benefits
which would arise and which include greenhouse gas (GHG) emissions reductions, local
employment creation and support to local enterprises.
The payment mechanism would be a unitary payment per kWh of electricity generated and
provided to the local grid (“the Tariff”) and would be governed by a PPA or similar contract
between the PPP partner and the Municipality. The Tariff cap would be determined by
Municipal policy and therefore, as noted, would be capped under existing policy at the tariff
paid by the Municipality for its bulk electricity supply from Eskom, plus a surcharge determined
by the Electricity Department which takes into account the value of local generation due to
avoided network power losses. The PPA would include suitable provisions for the annual
escalation of this Tariff. As a single good is being provided, that being kWh’s of electricity, a
single unitary payment can be used and no splitting of the payment between services is
envisaged.
In the event that a competitive procurement process resulted in a Tariff that was less than
the avoided costs of wholesale electricity there would be net financial benefit to the
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Municipality. The value of this benefit can only be determined following the procurement
process.
The key value-for-money drivers outlined in the PPP Guidelines are tabled below with an
indication of how they can be met within an envisaged project design and procurement
process.
Value for Money Driver How Addressed
Project objectives expressed
as measurable outputs
Yes. Unitary payments under the PPA to be in kWh of
power delivered at the project meter.
Incentive for demonstrable
innovation by the PPP partner
Yes. Final design to be provided by the PPP partner
within the bounds of technical, social and environmental
constraints. Technology choice and design innovation
incentivised by price competitiveness.
Transfer of substantial
financial, technical and
operational risks to the PPP
partner
Yes. Construction and operation risk to be wholly
transferred to the PPP partner.
Competitive procurement as
to which there are a sufficient
number of qualified private
sector firms that may bid
Yes. Can be based on many public and private sector
procurement processes for direct off-take solar PV
projects. There is clear evidence of a competitive and
competent local private sector.
Contract design reflecting
good PPP contracting practices
to provide for efficient
monitoring and regulation.
Yes. As above, there are numerous examples of similar
contracting processes and efficient monitoring and
regulation to be addressed in final procurement and
project contracts.
Increased direct revenue to
the municipality
No increase in revenue. Depending on final tariffs bid by
private parties there may be a reduction in direct
municipal costs of bulk power or a net zero change in
costs.
Increased socioeconomic
activities within the community
Yes. The project will lead to additional employment
during construction and to a lesser extent during
operations as well as multiplier effects of this
employment and expenditure.
Optimal use of under-
performing assets
Yes. The project would use existing idle land on
reservoir sites of the municipality.
Job creation As above.
BBBEE The procurement would include BEE requirements as
per Municipal supply chain policy. Further socio-
economic requirements can be included in the
procurement process as long as project viability is
maintained.
Aside from the direct costs and benefits of the project, there are other value for money
considerations, these including:
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Economic multiplier of local content
Increased national and local employment
GHG emission reductions
The potential for future green power sales at a premium
The potential for future green power sales in the future is an important item to consider as
this reflects potential realisable revenue from the project, rather than only economic value.
The value of renewable energy generation could be captured through the sale of specific green
power credits to off-takers willing to pay a premium for renewable energy. In addition, there
may be the potential for such sales to be used as carbon tax offsets in the future. These values
are all relatively difficult to quantify for a small project of this nature but can be added to the
analysis in due course if required by the municipality pursuant to final decisions on the project.
Based on the value for money assessment it appears that the Project would deliver value for
money in the delivery of the Project’s objectives.
The risk analysis conducted suggests that the risks of the project are very much in line with
typical risks of ring-fenced project finance transactions. As such, most of these risks, such as
construction over-runs, operational costs and generation performance can be contractually
passed to the PPP partner.
Some risks that would be retained by the Municipality can be regarded as non-material if
addressed correctly but worthy of consideration. These include the availability and completion
risks of the project which poses little risk to the Municipality’s power supply since the project
would provide such a small percentage of power purchases and any shortfall would simply
reflect in higher bulk purchases from Eskom.
The Municipality’s major material retained risks are:
Design risk: although the procurement process would be structured to pass this risk
to the PPP partner, the Municipality would retain some risk if this process was not
done correctly. For example, if any misrepresentations or incorrect information were
provided to the PPP partner that affected their project design and performance.
Environmental risk: this risk does not appear to be significant but it is likely that
the Municipality would need to undertake an initial scoping of any environmental risks
and to provide an appropriate environmental plan for the project to be met by the
PPP partner and contractually enforced.
Planning risks: this risk can be mitigated by the Municipality undertaking thorough
internal consultation and due diligence to ensure that all planning and related consents
are in place or could reasonably be obtained for the project.
Site risks: the sites for the project are to be provided and maintained and secured
by the Municipality and some of the risks of the ongoing maintenance of the sites will
remain with the Municipality for the period of the project and will need to be
addressed within the EWS operating plans and budget.
Regulatory risks: as above this risk can be mitigated by thorough consultation with
the key regulatory institutions, these being NERSA, National and Provincial Treasury,
and the DoE.
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Utilities (grid connection and grid stability) risks: the connection to the local
grid is the key interface, aside from the provision of the land itself, for the project.
There are a number of risks related to this. The first is that if the grid connection costs
and responsibilities fall to the Municipality there remain risks of cost over-runs and
technical problems in building the connection points and evacuating the power. There
also would be ongoing deemed energy payment risks if the grid was not available to
accept the power produced by the projects above the deemed energy thresholds. This
risk can be mitigated by participation of the Electricity Department in the transaction
team and confirmation from the department that the necessary grid studies and design
and cost estimates have been undertaken and that the required budget, approvals and
human resources are in place to undertake the required works. The default position
in the base case is that the costs of the grid connection will be borne by the PPP
partner. In this regard, the retained risk to the Municipality is that the costs provided
to the private partner for grid connection are incorrect and the Electricity Department
incurs higher actual costs of connection if they are responsible for the actual
construction of the grid connection infrastructure.
Key project NPV outputs are tabled below. This NPV analysis shown is that of the project
(based on the Low Case of 4.6MW), as opposed to the site level NPV analysis which was
conducted as part of the technical assessment and which was used to identify the likely sites
for inclusion in the base case.
The NPV analysis has made certain assumptions, that are shown within the project financial
model and are adjustable, around the percentage of risk retained by the Municipality.
Net Present Value (NPV) of Project
Against Baseline (all costs in Rm)
NPV Net Cost/Benefit
Municipal Costs / Benefits
Avoided Cost of Electricity Purchases (Baseline) 95.24
Grid Connection Costs =
- 0.00
Transaction Costs = -1.00 -1.00
M&E Costs = X% of Contract Payments/yr 1.00% -0.95
Retained Municipal Risk -2.23
Total Municipal Costs / Benefits 91.06
Project (PPA) Costs
Discount Rate = 9.10%
Period (years) = 20.00
NPV of Contract Payments
At Megaflex (plus Surcharge) -95.24 -4.18
2.5% below Megaflex -2.50% -92.86 -1.80
5.0% below Megaflex -5.00% -90.48 0.58
7.5% below Megaflex -7.50% -88.10 2.96
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The analysis shows that the Municipality requires a Tariff that is approximately 5% less than
Eskom Megaflex to recover its transaction costs and to cover the NPV of retained project
risks and to have a positive NPV - beyond that level there are net financial benefits to the
Municipality.
The remaining risks would largely fall to the PPP partner and would be specifically allocated
within the PPA. Therefore, it can be concluded that substantial technical, operational and
financial risk would be transferred to the PPP partner.
Procurement Plan
Although the evaluation has provided an indication that the project can achieve a positive
NPV for a private provider there are a range of other factors that affect the market capability
and appetite to deliver the project. It appears reasonably certain that market capability exists,
but there is less certainty on market appetite particularly since the projected private sector
returns are sensitive to certain assumptions and contract terms and may not be attractive to
private investment at the lower end of the range. It is therefore recommended that at the
minimum the Municipality should include an Expression of Interest (“EOI”) stage in the
procurement process before proceeding to a full Request for Proposals (“RFP”) as per the
Municipal Service Delivery and PPP Guidelines of the National Treasury2. The Guidelines note
that “the advantage of an EOI is that a municipality can make an informed decision, based on
market interest, about whether to proceed with the proposed PPP project.”
It is also suggested that the EOI stage is also used to test key PPA terms and conditions and
other risk transfer issues that would affect the ability and appetite of the private sector to bid
and to offer tariffs below the target level. In particular, the restriction on the Tariff being
below the equivalent Eskom Megaflex may make project financing difficult for private bidders
and it is recommended that this issue is discussed openly with market participants. Other key
considerations would be the degree of transfer of ground risk, site management risk and grid
stability risk to the PPP partner.
The RFP would need to follow the PPP approach of:
Treasury Views and Recommendations (“TVR”) stage Two A, TVRIIA, review by
Treasury of the draft RFP and associated contracts including the PPA
RFP issuance
Evaluation of bidder responses
TVRIIB value for money report and preferred bidder selection
This would be followed by final bidder negotiations and conclusion of contractual agreements,
following which the below would be addressed:
TVRIII Treasury approval
Solicitation of public participation and other actions required for s.33 of the MFMA
approval
2 National Treasury, 2005: Municipal Service Delivery and PPP Guidelines of 2005 (“the PPP Guidelines”).
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Council resolution supporting s.33 and the PPP contracts
Sign agreements
This procurement plan is established to support the key procurement objectives as prescribed
in chapter 11 of the MFMA by ensuring that the procurement that is required for the Project
occurs in a fair, equitable, transparent, competitive and cost-effective manner.
The Municipal Systems Act No. 32 of 2000 (“MSA”) and the Municipal Finance Management
Act No. 56 of 2003 (“MFMA”) require that the accounting officer of a municipality design and
manage the procurement process in a way that meets with legislative requirements. Key
applicable legislation includes:
The Constitution of the Republic of South Africa Act No. 108 of 1996 (“the
Constitution”);
Broad Based Black Economic Empowerment Act No. 53 of 2003 (“BEE Act”)
Municipal Finance Management Act No. 56 of 2003 (“MFMA”)
Municipal PPP Regulations of 2005 (“the PPP Regulations”);
Municipal Service Delivery and PPP Guidelines of 2005 (“the PPP Guidelines”)
Municipal Supply Chain Management Regulations of 2005 (“the MSCM Regulations”)
Municipal Systems Act No 32 of 2000 (“MSA”)
Preferential Procurement Policy Framework Act No. 5 of 2000 (“PPPFA”)
Preferential Procurement Regulations, 2011 (“PPPFA Regulations”); and
Labour Relations Act No. 66 of 1995 (“LRA”).
Chapter 11 of the MFMA, applies to the procurement by a municipality of goods and services,
including procuring a PPP. Any such procurement must be in terms of the municipality’s supply
chain management policy, which must comply with any prescribed framework, including the
PPP Guidelines, ensuring equity, transparency, competitiveness and cost-effectiveness.
The following sections of the MSCM Regulations are applicable to PPP Procurement:
Section 13: Listing general preconditions for consideration of bids;
Section 20: Describing the process for competitive bidding;
Section 21: Listing bid documentation requirements, including a requirement that any
bid; documentation must take into account “any Treasury guidelines on bid
documentation”;
Section 22: Public bid invitation requirements;
Section 23: Procedure for handling, opening and recording of bids;
Section 24: Negotiation parameters;
Section 25: Describing a two-stage bidding process;
Section 26: Requiring a committee system for competitive bids;
Section 27: Describing the make-up and duties of bid specification committees;
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Section 28: Describing the make-up and duties of bid evaluation committees;
Section 29: Describing the make-up and duties of bid adjudication committees;
Section 31: Processes for the procurement of IT related goods or services;
Section 32: Processes for the procurement of goods and services under contracts
secured by other organs of state;
Section 35: Appointments of consultants; and
Section 37: Unsolicited bids.
As noted there are further applicable regulations and guidelines which include:
The Electricity Regulation Act (“ERA”)
National Treasury Designated Sectors Instruction, Number 2 of 2016/2017 (“DSI#2”)
Treasury Views and Recommendations Stage I
Before the municipality proceeds to the next step in terms of procuring the Project, the
Treasury Views and Recommendations stage one (“TVRI”) of the PPP process will need to be
completed. This falls outside of the SA-LED scope of work but it is hoped that this feasibility
study will provide the bulk of the information and analysis required for that process.
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1 INTRODUCTION eThekwini Municipality (“the Municipality”) has established a guiding vision that by 2030 it will
be Africa’s most caring and liveable City, where all citizens live in harmony. In support of this
vision the Municipality has developed an Integrated Development Plan3 (“IDP”), an Energy
Strategy4 and a strategic approach to climate change in the form of the Durban Climate
Change Strategy (“DCCS”)5. These planning and strategy documents show a commitment by
the Municipality to implement climate change mitigation strategies as part of the long-term
vision for the city.
In particular, the Municipality plans call for the promotion of green power generation and a
strategy to “implement viable small-scale renewable energy generation such as micro-
hydropower, rooftop solar photovoltaic and anaerobic digesters within municipal assets.”
(DCCS, p.24). In line with this strategy, eThekwini Water and Sanitation department (“EWS”)
initiated a process to use available land on municipal reservoir sites for the establishment of
solar PV plants to provide renewable energy to the Municipal grid.
The project is conceived of as a single project, made up of a portfolio of solar PV plants each
under 1MW, to be financed, designed, built, owned and operated by a private sector partner.
The Municipality would purchase electricity from the project under a long-term Power
Purchase Agreement (“PPA”) under which all the construction, operation and generation risk
would be passed to the PPP partner. The Municipality would provide the required municipal
property for the plants under a land availability or lease agreement to the project owner. Due
to the use of municipal land and the effective partnership between the Municipality and the
private sector in the provision of renewable electricity the project was deemed to be a
potential Public Private Partnership (“PPP”). The private partner would therefore be an
Independent Power Producer (“IPP”) in partnership with the Municipality and is referred to
as “the PPP partner” or the PPP partner.
1.1 Project Background and Report Objectives
The USAID supported South Africa Low Emissions Development (“SA-LED”) programme was
asked to assist the EWS with a feasibility assessment of the proposed Project. The Project
was initially registered as a PPP by the Municipality with the National Treasury on 27 March
2012. As the intention of the EWS is to take the Project through the PPP process as outlined
in the relevant municipal legislation SA-LED has prepared the feasibility assessment as far as
possible in accordance with the requirements of a Feasibility Study under the Municipal
Systems Act (“MSA”) and also Municipal Finance Management Act (“MFMA”) requirements
so as to allow the Municipality to use the study in the requisite steps in the process.
The objective of this feasibility study is therefore to provide the required evaluation under
the PPP process to allow the Municipality to proceed to the Treasury Views and
3 eThekwini Municipality, Integrated Development Plan, 5 Year Plan, 2017/18 to 2021/22.
4 eThekwini Municipality, Energy Strategy, 2008.
5 eThekwini Municipality Environmental Planning and Climate Protection Department, Durban Climate Change Strategy, approved by eThekwini Municipality Council on 24th June 2014.
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Recommendations I (“TVR I”) stage of the PPP process, prior to submission to the Municipal
Council. The report includes the relevant components of the Feasibility Evaluation and
Preliminary Design Study in line with National Treasury’s Municipal PPP Guidelines (“the
Guidelines”).
A covering letter from the accounting officer requesting Treasury Views and
Recommendations (“TVR”) will be required prior to proceeding to TVRI stage of the PPP
process. This covering letter is to be provided by the eThekwini Municipality.
The specific objectives of the feasibility study are, taking into account all relevant information,
to:
Explain the strategic and operational benefits of the proposed mechanism, including a
PPP, for the Municipality in terms of its objectives.
Describe in specific terms:
o The nature of the PPP partner’s role in the PPP;
o The extent to which this role, both legally and by nature, can be performed by
a PPP partner;
o Describes how the proposed agreement will:
Provide value for money to the Municipality;
Be affordable for the Municipality;
Transfer appropriate technical, operational and financial risks to the
PPP partner; and
Impact on the Municipality’s revenue flows and its current and future
budgets.
Explain the capacity of the Municipality to effectively monitor, manage and enforce the
agreement.
Role of the SA-LED Programme
Under the PPP Guidelines provision is made for the appointment of a Transaction Adviser to
assist a municipality in the PPP process. It is noted that the USAID/ South Africa Low
Emissions Development Programme (SA-LED) was not formally appointed as Transaction
Adviser in terms of the PPP Guidelines by the eThekwini Municipality. SA-LED has been
assisting the Municipality with an assessment of the feasibility of the envisaged project and was
requested to compile this report in the form and substance required of a PPP feasibility study
report.
It is therefore noted that SA-LED has not necessarily met the full scope of work of a
Transaction Adviser under the PPP Guidelines and some additional activities and analysis may
be required to comply with all aspects of the PPP process. These are noted within the
feasibility study where appropriate and may need to be carried out by the Municipality – for
example public sector engagement and public consultation if required.
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1.1.1 Determination of the Project as a PPP
The PPP Guidelines defines a PPP as a commercial transaction between a municipality and a
PPP partner in terms of which the PPP partner:
a) Performs a municipal function for or on behalf of a municipality or acquires the
management or use of municipal property for its own commercial purpose; or both
performs a municipal function for or on behalf of a municipality and acquires the
management or use of municipal property for its own commercial purposes.
b) Assumes substantial financial, technical and operational risks in connection with:
i. The performance of the municipal function
ii. The management or use of the municipal property; or
iii. Both
c) Receives a benefit from performing the municipal function, or from using the municipal
property or both, by:
i. Consideration to be paid or given by the municipality or a municipal entity
under the sole or shared control of the municipality;
ii. Charges or fees to be collected by the PPP partner from users or customers
of a service provided to them;
iii. A combination of the benefits referred to in subparagraphs (i) and (ii).”
As per this definition the Project has been deemed to be a PPP because the private sector
project owner of the proposed solar PV project:
Acquires the use of municipal property for its own commercial purpose, this being the
siting of the PV plants;
Assumes substantial financial, technical and operational risks in connection with the
use of the municipal property, in the form of ongoing generation, insurance, operations
and maintenance of the PV plants;
Receives a benefit from using the municipal property by charges to be collected by the
PPP partner from users of a service provided to them, in the form of sale of electricity
from the PV plants to the municipality under the PPA.
In addition to the above triggers for a PPP, the Project also meets the substance of a PPP in
that the envisaged contracting mechanism, under which the Municipality will enter into a long-
term PPA with a private provider, envisages a partnership between the Municipality and a
private provider in the provision of power generation that, while not a municipal function in
terms of the Constitution, is a function that could be, and is at times already, delivered by the
Municipality.
Further, as a long-term contract, the PPA will be subject to the procedures prescribed under
Section 33 of the MFMA which addresses contracts that have budgetary implications longer
than three years in extent. The analysis presented in this feasibility study should be sufficient
to address the information and analysis that the Municipal Council needs to take into
consideration under the Section 33 process.
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1.1.2 Feasibility Study Objectives
The Project is envisaged as a portfolio of PV plants of varying sizes, each being connected to
the Municipal electrical distribution grid at separate local connection points. The feasibility
study focuses on refining the definition and scope of the Project. In particular it reviews the
available reservoir sites against their suitability for solar PV siting and the optimal plant size
per site.
As the economic and technical feasibility of PV plants is size dependent a further objective of
the study is to determine the minimum feasible plant size from a financial and technical
perspective. This in turn allows the feasible sites to be filtered and a target total portfolio size
determined. The study is structured in such a way that it allows changes in the envisaged site
selection and project size based on changes in input assumptions, such as the plant capital
costs.
The study also aims to give an indication of further work required to be undertaken prior to
project procurement and considerations to be taken into account in the final project design
and procurement phase. This latter element includes an assessment of the risks of the Project
and on which party these risks fall and considers suitable allocation of such risks. A final
objective of the study is to suggest a process for the procurement phases of the Project.
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2 NEEDS ANALYSIS The Municipality has historically been a leader in exploring alternative, low carbon energy
solutions through the use of municipal assets. Various policies, plans and strategies provide a
basis for the Municipality’s support of renewable energy and climate change mitigation.
2.1 Municipality’s strategic objectives
Integrated Development Plan
At the broadest level the municipal IDP includes the principles of sustainability and resilience
which are seen as the “mainstreaming and coordinating environmental planning and climate
protection intended at promoting greater resilience to climate change risks and impacts,
protecting vulnerable communities, protecting environmentally sensitive areas and prime
agricultural land, promoting a green economy and increasing support for renewable energy
generation and low carbon development”.
This broad principal is further defined in support of Outcome EE4, Improved Energy
Sustainability, in line with the Municipal Circular on Rationalisation Planning and Reporting
Requirements for the 2018/19 MTREF issued by National Treasury on 30 November 2017.
Under this outcome the IDP states that “the Municipality, through its Energy Office, has
developed the eThekwini Municipality Energy Strategy which is implemented via Plan 1 and
Programme 4 of the IDP. This strategy, as part of climate change intervention and mitigation,
focuses on the total renewable energy capacity that is available within the municipal
jurisdiction via Independent Power Producers (“IPPs”), own generation and embedded
generators.”
The specific outcome is measured as renewable energy capacity available within the municipal
jurisdiction as a percentage of Eskom supply capacity to the municipality. As this is a new
performance indicator for the Municipality there is as yet no baseline and specific targets are
currently being determined however the envisaged project would positively contribute
towards this outcome and is well supported by other policy objectives as described further
below.
eThekwini Municipality Energy Strategy
The Energy Strategy was first developed by the Municipality in 2008 and builds upon work
already carried out in the areas of Greenhouse Gas (“GHG”) Inventory development and
State of Energy reporting. It further derives impetus from the work embodied within
eThekwini Municipality’s Climatic Future for Durban, which identifies the Climate Change-
related challenges which lie ahead for the city and delivers appropriate responses to address
those challenges. In support of this vision the strategy says that the Municipality will:
Encourage sustainability in energy sector development and energy use through efficient
supply-side and demand-side practices and increased uptake of renewable energy
sources,
Thereby minimising the undesirable impacts of energy use upon human health and the
environment, particularly climate change and contributing towards secure and
affordable energy for all.
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In particular the Energy Strategy promotes green power purchases by public buildings and the
promotion of green power generation. Noting that this is a fast-changing area the strategy
states that “The Action Plan will also ensure that eThekwini Municipality continues to evaluate
other alternative power generation options into the future. These would include a range of
renewable energy technologies as deemed technically and financially feasible.”
Durban Climate Change Strategy (“DCCS”)
The DCCS was approved by the eThekwini Municipal council in June 2015. This is an
integrated mitigation and adaptation strategy focused on ten key themes: Water, Sea-Level
Rise, Biodiversity, Health, Food Security, Energy, Transport, Waste, Economic Development
and Knowledge Development. Objective F.1 of the strategy is that 40% of Durban’s electricity
consumption is supplied from renewable energy by 2030 in line with the national long-term
mitigation targets. More specifically, Goal F.1.2 includes the goal to “implement viable small-
scale renewable energy generation such as micro-hydropower, rooftop solar photovoltaic and
anaerobic digesters within municipal assets.” (DCCS, p.24).
eThekwini Electricity Unit Grid Connection Guidelines
In anticipation of local generation from renewable energy sources and the export of electricity
from these sources into the local distribution grid, the eThekwini Electricity Department has
published Guidelines for Generators Connecting to the Grid (“the Connection Guidelines”).
The Connection Guidelines state that in trying to contribute to national renewable energy
targets, relieve the stressed electrical grid and contribute to climate change mitigation targets
set, the eThekwini Municipal Council fully supports generation of power within its boundaries.
The Connection Guidelines also point to some advantages of localised generation, these
including:
Reduction in Transmission Losses. Transmission of electricity over distances
incur transmission losses which can range from 3-6% and therefore these losses are
avoided with local generation;
Reduction in Transmission Construction Cost. When transmission distances
are reduced, the construction cost of Substations, Transmission Towers and Rights-
of-Way would also be reduced or eliminated. Especially in city-centres where
transmission is achieved through underground cables there could be substantial savings
involved as the cost of these cables can be 10-15 times that of overhead lines.
Security of supply. When connected to the distribution system, multiple localised
generators can make a significant contribution to the security of supply and to help
achieve the Government’s objectives of introducing IPP’s.
The Connection Guidelines note that the Municipal Council in 2011 authorised the
Municipality’s Electricity Department to enter into Power Purchase Agreements (“PPAs”)
with renewable energy power generators to promote the localised generation of electricity.
However, this must be at no additional cost to Council (see below Council Authorisation).
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Table 1. Extract from eThekwini Council Authorisation on Electricity PPAs
The Municipality’s Electricity Department, the buyer of the generated electricity, sees itself
mainly as a distributor of electricity and does not have preference for locally generated
electricity over other sources. The department will consider buying power from generators
as long as the quality of supply is well-managed and the electricity price is the same or less
than that supplied by the Eskom grid.
2.2 Greenhouse Gas Reduction and Climate Change Mitigation
The project will have a direct and measurable contribution to the reduction of greenhouse
gases (“GHGs”) and hence climate change mitigation through the displacement of electricity
from largely coal-based power generation by electricity from a renewable energy source with
no emissions created during generation.
The GHG emission reductions that would be due to the project are tabled below. These
were calculated by SA-LED using the USAID Clean Energy Emission Reduction (“CLEER”)
Tool. The CLEER Tool is a user-friendly calculator based on internationally-accepted
methodologies, enabling users to calculate emissions reduced or avoided from clean energy
activities (see: https://www.cleertool.org/).
Table 2. Expected Greenhouse Gas Reductions from the Project
Period
Emissions Reductions
(tCO2e)
4.6 MW 9.8 MW
2019 - 2020 13,570 32,700
2021 - 2025 33,330 80,300
2026 - 2030 32,500 78,400
Total GHGs Reduced/Avoided through
2040
144 400
347 200
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2.3 Budget
The Municipality budgeted R8 919 million for the bulk purchase of electricity in 2018/196. The
purchase of electricity under a PPA from the project would fall part of this same budget and
hence would displace equivalent amounts of power purchased from Eskom. Based on the
estimated minimum size of the project of 4.6MWp at 2018/19 tariff levels this would amount
to approximately R5.8 million per annum as shown in the table below.
These values are based on the weighted average tariffs for the project based on the Eskom
Megaflex tariff schedule applicable to the Municipality in 2018/2019 and adjusted for the time
of generation of a solar PV project and the voltage surcharge offered by the Electricity
Department to embedded generators. The tariff is therefore not the average cost of bulk
electricity purchased by the Municipality which would simply be the total annual kWh
purchased divided by total annual cost.
Table 3. 2018/2019 Municipal Expenditure on Equivalent Power Purchases (at
4.6MWp – low case)
Weighted Average Tariff with Surcharge 81.7 c / kWh
Total Power Purchased 7 118 MWh / yr
Rand Value of Power Purchased 5 813 982 R / yr
At the larger scale of 9.8MWp the displaced electricity would be correspondingly larger and
would be approximately R11.3 million per annum as tabled below.
Table 4. 2018/2019 Municipal Expenditure on Equivalent Electricity Purchases (at
9.8MW – high case)
Weighted Average Tariff with Surcharge 81.7 c / kWh
Total Power Purchased 14 601 MWh / yr
Rand Value of Power Purchased 11 926 097 R / yr
The budget amounts of between R5.8 million and R11.9 million reflect the 2018/2019
expenditure per annum on power purchases equivalent to those of the project and hence the
budget envelope available for power purchases under the PPA in that year. The estimated
budget allocations for the Project would therefore be approximately 0.07% and 0.13% of the
total budget for bulk electricity.
The EWS has informally indicated its willingness to enter into a contract longer than three
years. The municipality will in due course need provide a letter from the Chief Financial
Officer confirming that the required budget can be committed to under a 20-year PPA, or
other contract length as ultimately approved by the Municipal Council.
Note that further technical analysis and site evaluation is currently underway which may refine
the analysis of the time of day and seasonal forecast electricity generation and which therefore
6 eThekwini Medium Term Revenue and Expenditure Framework, 2018/2019 To 2020/2021
31
may lead to an adjustment in the weighted average tariff. However, this adjustment is not
expected to be considerable.
2.3.1 Distribution Loss Savings
As a generation project located within the distribution network there are also benefits to the
Municipality from reduced energy losses within the network. The above values take into
account these reduced distribution grid losses benefits as the value of these savings are
included as a tariff surcharge paid to locally generated electricity by the Electricity Department
over the Eskom price of electricity. The value of these savings from distribution losses makes
up 10.05% of the total purchase price, or R0.58 million in the low case and R1.2 million in the
upper case.
2.3.2 Medium- and Long-Term Budget Implications
In the MTREF period the municipality has budgeted annual increases for Eskom tariffs of 8.0%
for 2019/20 and 2020/21. Based on this indexation, the envisaged equivalent expenditure on
the Project outputs of the Municipality from its bulk electricity purchase budget would
increase to R13.9 million by 2021 in the high case as shown in the table below.
Table 5. Municipal Expenditure on Equivalent Electricity Purchases 2019 – 2021
Indexed (R / yr)
Project Size
(MWp DC) 2018/19 2019/20 2020/21
4.6MW 5 813 982 6 279 101 6 781 429
9.8MW 11 926 097 12 880 185 13 910 599
Entry into a long-term PPA with a private provider would have longer term budget
commitments. These commitments would not fall within the three-year MTREF budget.
If a PPA was entered into at a purchase price at, or lower than Megaflex rates, then no
additional costs would be anticipated to occur over the term of the PPA over the baseline
Eskom power purchases of the municipality. The envisaged power purchases make up a small
fraction of current bulk power purchases. In the Low Case the power purchased from the
Project would amount to approximately 0.04% of the total power purchased by the
municipality and in the high case it would amount to approximately 0.13% of the total power
purchased.
2.3.3 Additional Current Budget Allocation
The Project will be located on current reservoir sites managed by the EWS. These sites have
varying degrees of maintenance and up-keep and require typical site maintenance of grass-
cutting and clearing of vegetation, painting and so forth. There may also be site security
requirements which may increase in the event of location of the solar PV installations on the
sites.
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The EWS has indicated that any additional site maintenance costs due to the proposed Project
will be allocated to the PPP partner and therefore no additional budget allocation for the
reservoir sites operations and maintenance will be required in the EWS operating budget.
As discussed further below, there will also be the requirement for grid connection costs to
be included in the Project costs. These costs have been provided by the Municipality following
preliminary design and costing by the Electricity Department and are estimated at R7.9m for
the low case made up of seven discrete sites. The EWS has indicated that these costs are also
intended to be fully borne by the PPP partner and hence will have no budget implications for
the Municipality if so allocated.
2.3.4 Revenue Implications
The Municipality does not receive any specific grants or other revenue in support of bulk
electricity purchases. Electricity is a trading services account and revenue is raised from billing
of municipal customers which will not be affected by the Project.
2.4 Institutional analysis
The project is being prepared and implemented by the EWS department in collaboration with
the Electricity Department. The requirements in terms of management, evaluation,
negotiation and implementation of the project are discussed further below.
2.5 Output specifications
2.5.1 Primary Goal
The primary goal is to utilise available land on EWS reservoir sites to produce renewable
energy generated by solar PV plants for export into the municipal distribution grid. The
electricity will displace the purchase of electricity from the Eskom transmission grid, thereby
also reducing the GHG emissions of power use in eThekwini, promoting embedded
renewable energy generation, and starting to diversify sources of electricity supply. At any
tariff level below the Eskom bulk purchase tariffs there will also be direct cost savings to the
municipality.
2.5.2 Specific Outputs
The Project is specified as a portfolio of individual grid-tied solar PV plants that will each
connect separately into the municipal distribution grid at the nearest available connection
point. Specific targeted outputs are:
AC power generated at suitable voltages from solar PV sources to be exported into
the distribution grid in compliance with the Grid Code and any additional municipal
requirements;
Individual installations to be equal to or greater than 100kWp of AC capacity;
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Individual plant sizes installations to be less than 1MWp of AC capacity;
Design and operational philosophy to maximise the generation of electricity from the
available land area and solar resource.
It is not anticipated that the Project will include battery storage in the first phase.
2.5.3 Minimum Standards
The key minimum standards of the Project are:
Use of tier 1 solar PV manufacturer with proven technologies;
Forecast availability of greater than 98%;
Fixed tilt ground-mounted systems;
Compliance with the Grid Code;
Compliance with the National Treasury Designated Sectors Instruction Number 2 of
2016/2017 which provides for the “Minimum Threshold for Local Production and
Content for Solar Photovoltaic System and Components”;
Compliance with health and safety specifications as determined by the municipal
Electricity Department.
2.5.4 Key Performance Indicators
The Project’s key performance indicators are:
Sum of the quantity of electricity delivered to the metering point across the portfolio
in kWh / month and kWh / year;
Plant availability reported on a monthly and annual basis;
Reporting on socio-economic obligations;
Maintenance of any regulatory requirements including Grid Code compliance and
NERSA registration;
Generation of monthly and annual performance and compliance reports;
Generation of annual financial report.
Other performance monitoring requirements may be determined at the procurement stage.
2.5.5 Key Service Interfaces
The project has limited interfaces with municipal operations. The main interfaces envisaged
and potential impacts and responses are tabled below:
34
Table 6. Key Service Interfaces
Operational Issue Nature of Impact and
Consequence
Response
Plant outage Technical unavailability of the plant Grid code and Electricity
Department requirements to
be provided by the
municipality as part of the
procurement specifications
Grid outage Outage of the municipal grid (such
as due to load-shedding or grid
maintenance)
Grid code and Electricity
Department requirements to
be provided by the
municipality as part of the
procurement specifications
Grounds
maintenance
Poor maintenance of site under
supervision of the project leading
to vegetation over-growth and
impact on reservoir maintenance
and operations.
If maintenance is the municipality’s
responsibility, then potential claim
for lost performance by the PPP
partner.
Municipality confirmed that the
intention is to pass full
responsibility for site
maintenance to the PPP
partner
2.5.6 BBBEE and Socio-Economic Targets
The broad-based black economic empowerment (“BBBEE”) and other socio-economic
objectives of the municipality are an important component to be included in the PPP structure
and procurement criteria for the Project. These components have not been included within
the scope of this feasibility study but will need to be addressed prior to the procurement
process and incorporated into the marketability and appetite determination, procurement
process and contract documentation.
The Municipality has confirmed that the procurement of the Project will need to be in
accordance with the Contract Participation Goals (“CPG”) as per the Municipal supply chain
management guidelines. These goals will therefore need to be included in any RFP to be issued
and any associated obligations on the private partner included in contract documentation.
Once these have been incorporated into the PPP structure it is recommended that the PPP
partner shall report on the CPG requirements and any other socio-economic obligations at
least every six months and supply a BBBEE scorecard annually in the reporting process.
2.5.7 Local Content
The DTI / National Treasury Minimum Threshold for Local Production and Content for Solar
Photovoltaic System and Components will be applied. The PPP partner shall confirm
35
compliance with the local content obligations and ability to meet these obligations through
the provision of a component breakdown and bill of quantities prior to construction.
The PPP partner shall further confirm compliance with the local content obligations through
the provision of as-built drawings and bill of quantities on completion of construction.
2.6 Project Definition
The definition of the project is based on a technical simulation of the potential installations
given the site availability. On the basis of the simulation the potential portfolio of plants has
been identified as shown in the table below.
Key design considerations are:
The largest installation is a 826kWp system having an AC capacity of 750kW and
producing 1 288MWh of energy per annum;
A minimum size of 100kWp has been used as the lower size limit per installation to
avoid sub-optimal installations and to limit the portfolio to a manageable number of
sites;
A maximum size of 1 000kWp has been used as the upper size limit per installation to
avoid the need for a generation license in terms of current regulations;
The DC/AC ratio for all the simulations was in the range from 1.25:1 to 1.08:1. These
ranges can be further optimised depending on the detailed design and final technology
selection;
A key limitation per site is the available AC capacity of the nearest grid connection. If
the grid connection does not have enough capacity for the maximum AC power
produced by the inverters, then the design capacity will need to be reduced;
Completing the installation of all 52 projects will result in a total installed peak DC
capacity of 9.8MW (“the High Case”). This is made up of 39 separate sites;
Completing the installation of only those installations with a positive net present value
(“NPV”) will result in a total installed peak DC capacity of 4.6MW (“the Low Case”).
This is made up of the seven largest sites in the portfolio. This Low Case has been
used as the basis for the financial modelling;
It is important to note that final portfolio determination and hence the final total size of the
project will be made following further technical, financial and risk assessment including:
Availability of local grid connections;
Final site filtering based on determined characteristics such as ground conditions,
security, shading and accessibility;
Ability of the private sector to meet the tariff benchmark.
As the private sector bid tariffs cannot be known until the procurement process, it may also
be appropriate to design a procurement process that allows for some flexibility in the final
total project size as the scale has limited impact on the value for money assessment.
36
2.6.1 Use of Municipal Assets
The municipal assets to be used for the Project will be the identified reservoir sites for the
installations as tabled above. The reservoir sites will be maintained to the normal standard
and no additional maintenance requirements will be imposed on the municipality for the use
of these assets by the PPP partner.
Each separate installation will also require a municipal grid connection which will be provided
by the Electricity Department and which will remain an asset of the municipality. The
Municipality has indicated that their intention is that the default approach is that the full costs
of these new grid connections are borne by the PPP partner.
For contractual reasons each site will have a purchase meter, owned by the Municipality, and
a sales meter owned by the Project.
37
3 TECHNICAL SOLUTION OPTIONS ANALYSIS In this section the various technical options for meeting the objectives are identified and
evaluated and a technical option recommended.
3.1.1 Technical options considered
The primary objective of the proposed project is to displace a portion of the GHG intensive
electricity procured from the national grid with renewable energy source from renewable
energy generation within the eThekwini distribution grid using available land on EWS reservoir
sites.
Therefore, the technical options to the project are alternative forms of renewable energy that
could be deployed on the available sites. A consideration of these options was conducted to
select the preferred option. A summary of the technical option comparison is tabled below.
Table 7. Technical Options Evaluation
Option Explanation Reason for Elimination
Wind Power Small scale wind-turbines Require extensive and expensive
wind-monitoring to determine
eligibility
Not easy to scale to suit sites
Complex planning requirements due
to height
Sites not equally suitable due to
different environmental conditions
Biomass Use of biomass to
produce power through
anaerobic digestion or
combustion
Sites do not provide the required
biomass resources required at
sufficient scale
Not economically viable at small
scales
Hydropower Use of energy potential
of falling water Some locations within the eThekwini
water network do have suitable
volumes of water being transported
using gravity. These have been
separately identified and are the
subject of a separate power
generation feasibility study and do not
apply to any of the reservoir sites
under consideration.
Solar Thermal Use of the sun’s
radiation to produce
electricity through
heating water or other
Cannot be done at small scales cost
effectively
38
Option Explanation Reason for Elimination
liquid to steam to run a
turbine Typically requires higher solar
radiation zones with lesser cloud
cover during the year
Solar PV (ground
mounted fixed
tilt)
Use of the sun’s
radiation to create
electricity through a
photo-chemical effect
using PV panels. Panels
mounted on fixed
structures with an
orientation tilted to
receive the maximum
solar radiation
Suitable at small scales
Solar radiation resource can be
estimate cost effectively through
satellite studies
Easily scalable to different sized sites
Cheapest renewable energy
technology at small scales
Relatively simple technology with
limited moving parts and maintenance
concerns
Solar PV
(rooftop)
Use of the sun’s
radiation to create
electricity through a
photo-chemical effect
using PV panels. Panels
mounted on rooftops
that have sufficient
structural strength and
the correct orientation
to maximise solar
radiation
Suitable at small scales
Solar radiation resource can be
estimate cost effectively through
satellite studies
Easily scalable to different sized sites
as long as suitable rooftop space is
available
Cheapest renewable energy
technology at small scales
Relatively simple technology with
limited moving parts and maintenance
concerns
Lower site maintenance and security
concerns than ground mounted
system
Solar PV (ground
mounted
tracking)
As above but with panels
mounted on structures
that track the sun in one
axis during the day as the
sun moves across the sky
to improve the amount
of solar radiation
received.
Additional complexity of the tracking
system raises concerns around long-
term maintenance, especially on many
distributed sites
Less suitable for small sites as there is
a higher installed capital cost.
Solar PV with
storage
As above but with the
addition of storage in the
form of batteries
More complex to manage technically
Complex to evaluate different options
due to different battery types with
different capital lifespan, operating
parameters and operational costs.
39
Option Explanation Reason for Elimination
Financial benefits are very dependent
on tariff structures that may change.
Storage can be added later.
An example of a similar installation is shown in the photograph below, which is a 200kW solar
PV project installed by the Ekurhuleni Metropolitan Municipality.
Figure 1. Ekurhuleni 200kW Solar PV Project at the OR Tambo Precinct,
Wattville
On the basis of the above analysis, the conventional and well proven option of ground-
mounted solar PV with fixed tilt mounting structures was selected as the preferred option
which meets the Municipality’s objectives.
3.2 Evaluation of the Preferred Technical option
A high level technical and financial analysis was conducted for 39 reservoir sites of the list of
440 provided by the eThekwini Municipality. To provide consistency across the evaluation a
set of standard specifications of the plants was used, this being:
Fixed tilt system with a pitch distance of 3m;
The tilt angle of the modules at 30 degrees;
Soiling losses = 3%;
Light Induced Degradation = 1.5% per annum;
Module quality loss = 0.6% (positive power tolerance);
Auxiliary power loss = 0.4%;
Initial Module degradation = 0.5%.
40
The above factors are based on typical values from manufacturers and third-party tests. Soiling
losses can vary depending on the cleaning strategy employed.
3.2.1 Solar PV Module Technology
The technocology of solar pv modules is changing each year. In determining the best type of
solar panel technology to place on the reservoirs, a few factors come into play. First, the
efficiency, or the amount of sunlight converted into energy, of the panel must be relatively
high. compared to the other technologies. Currently, the most efficient panel is
monocrystalline technology, reported at 24.7% efficiency, followed by polycrystalline
technology, reported at 19.8%.
Second, the cost associated with each technology must be considered. Monocrystalline costs
are generally higher than those of polycrystalline panels. Third, availability must be considered.
Monocrystalline and polycrystalline technologies are both readily available as they are already
widely used by solar technology manufacturers.
Module technologies are differentiated by the type of PV material used, resulting in a range of
conversion efficiencies from light energy to electrical energy. The module efficiency is a
measure of the percentage of solar energy converted into electricity.
Two common PV technologies that have been widely used for commercial- and utility-scale
projects are crystalline silicon (monocrystalline or polycrystalline) and thin film. Currently
both mono- and polycrystalline are good options, however with the new PERC technology
the focus has shifted to monocrystalline technology. PERC technology boosts efficiency
through the addition of a layer to the back of a traditional solar cell, which provides several
benefits to the cell's production. PERC solar cells are an exciting technology because of the
efficiency gains they provide over standard solar cells.
3.2.1.1 Crystalline Silicon
Traditional solar cells are made from silicon. Silicon is quite abundant and nontoxic. It builds
on a strong industry on both supply (silicon industry) and product side. This technology has
been demonstrated to be functional for over 30 years in the field. The performance
degradation, a reduction in power generation due to long-term exposure, is under 1% per
year. Silicon modules have a lifespan in the range of 25–30 years but can keep producing
energy beyond this range.
Typical overall efficiency of silicon solar panels is between 12% and 18%. However, some
manufacturers of mono-crystalline panels claim an overall efficiency nearing 20%. This range
of efficiencies represents significant variation among the crystalline silicon technologies
available. The technology is generally divided into mono- and poly-crystalline technologies,
which indicates the presence of grain-boundaries (i.e., multiple crystals) in the cell materials
and is controlled by raw material selection and manufacturing technique.
3.2.1.2 Thin Film
Thin-film PV cells are made from amorphous silicon (a-Si) or non-silicon materials, such as
cadmium telluride (CdTe). Thin-film cells use layers of semiconductor materials only a few
micrometers thick. Due to the unique nature of thin films, some thin-film cells are constructed
41
into flexible modules, enabling solar energy covers for landfills, such as a geomembrane
system. Other thin-film modules are assembled into rigid constructions that can be used in
fixed tilt or, in some cases, tracking system configurations.
The efficiency of thin-film solar cells is generally lower than for crystalline cells. Current
overall efficiency of a thin-film panel is between 6% and 8% for a-Si and 11% and 12% for
CdTe.
Industry standard warranties of both crystalline and thin-film PV panels typically guarantee
system performance of 80% of the rated power output for 25 years. After 25 years, they will
continue producing electricity at a lower performance level.
The optimal solar panel technology for the proposed project given the limited space available
at the sites, the mono-crystalline PERC technology will be a good option since the modules
have ratings up to 400Wp, i.e. you can fit more power in the same space. The factors that
would likely determine the likely technology installed by the private parties: efficiency, cost-
effectiveness and availability. The technology should be highly efficient over the entire panel
lifespan, while maintaining a reasonable cost that appeals to potential project investors.
3.2.2 Site Assessment
The coordinates and available area for each reservoir were provided by EWS. The list
provided included 440 sites ranging in area from 15 916m2 to 5.4m2. In order to limit the
number of sites, a design sizing limit of 100kWp was set as this was considered the minimum
feasible size for a ground-mounted PV system. This resulted in assessments being initially
conducted for 52 sites which was then further refined to 39 sites.
The appropriate minimum size site was further refined during the economic analysis. This was
done based on financial viability and is discussed further below. This resulted in a High Case
of 39 sites with a total installed capacity of 9.8MWp and a Low Case of seven sites with a
total installed capacity of 4.6MWp.
Three sites were visually assessed in March 2018, including two of the largest sites, by SA-
LED and EWS staff as part of the feasibility assessment. The sites were assessed to determine
the typical ground conditions, topography, shading and potential grid connection. Each of the
areas was found to be flat and located on a small hill. The larger reservoirs had stones and
grass on the ground. As discussed later, prior to final site selection all the sites will need to
be similarly assessed against similar conditions to identify fatal flaws and eliminate unsuitable
sites.
The following table lists all assumptions which were made.
No planning exclusion zones exist on any of the sites;
There will be no requirement for perimeter fencing;
The irradiation values are fairly consistent across all the sites;
95% of the available area will be utilised for installation;
Metering point will be at the reservoir (i.e. excludes grid losses);
Grid connection point is close by and there are no grid constraints;
42
All grid connection costs are borne by the Municipality7.
3.2.3 Structural assessments
No structural assessments were conducted, however it is advisable that a structural
assessment of the sites be undertaken during the detailed engineering analysis, either by the
Municipality or passed on as a ground risk to the PPP partner with suitable allowance for site
inspection during a procurement process.
3.2.4 PVSYST Yield Simulations
Each site was simulated using the PVSYST 6.47 simulation platform. Meteonorm
meteorological data was used as irradiation data provided by eThekwini could not be used
due to:
Missing data;
Uncertain calibration of pyranometers;
Unknown tilt angle of measurement.
Tilt and orientation
PV modules were oriented facing north to optimise production from the modules in the
simulation. In order to reduce shading and optimise performance the modules were modelled
in landscape on a fixed tilt system with a pitch distance of 3m. The tilt angle of the modules
was set at 30 degrees to allow for an optimal power profile during the day. The selection and
design of the actual structure will depend on the final design and local environmental
conditions.
The modules selected for the simulations were BYD 320Wp modules. These are 72 cell
modules. BYD is a tier 1 manufacturer and have supplied modules in South African projects.
The module is also assembled locally through ART Solar.
The module selection can be either 1 500V or 1 000V. In the simulations, the larger systems
made use of 1 500V systems and smaller systems used the 1 000V. This was due mainly to
not having sufficient data on 1 500V string inverters. The 1 500V system has lower balance of
system costs due to longer string lengths resulting in lower cables and losses. These options
can be further analysed in the detailed engineering assessment.
The inverters utilised included SMA and Sungrow. Other inverter options are also available
however the changes in yield output will not be significant. SMA and Sungrow are both proven
technologies and comply to local municipal requirements. Other inverters are also available
such as Huawei and KACO.
7 Note that this assumption was made during the technical analysis but was later altered after consideration by the EWS and their determination that the default approach would be that all grid connection costs are borne by the PPP partner.
43
Note that the specific manufacturers selected for the simulation do not indicate that the
project itself would need to use the same manufacturers. A technology solution proposed
would simply need to meet the minimum technical requirements outlined in the procurement
process.
Reservoir Area Measurements
For the purposes of the feasibility study reservoir areas were taken to be the values provided
by eThekwini staff. The actual area used for the design and simulation was 95% of the actual
areas provided in order to consider space for perimeters, transformers and other balance of
plant. This will vary depending on the detailed engineering and actual site visits.
System Sizing
The total power and energy output were calculated based on the area available for installation
whilst considering the shading losses, module configuration and while optimising pitch
distance. No losses were considered for grid connection. The net result of the analysis is
shown in the table below.
44
Table 8. Project Portfolio – Installation Capacity and Yield Per Reservoir Site
45
Figure 2. Simulation results of DC Capacity and Expected Energy Yield Per
Reservoir Site
The analysis of the technical options provided the key input data into the financial analysis and
project due diligence stage.
3.3 Key Parameters for Financial Analysis
A financial evaluation was performed on each of the identified sites. The initial evaluation was
based on a simplified Net Present Value (“NPV”) calculation. This was followed by the
development of a more accurate financial model which was based on a base case of a
combined 4.6MW project and was designed to determine the returns to a PPP partner
participant in the Project and to allow for the EWS to conduct a range of sensitivity analyses
or scenarios in preparation for a procurement process.
3.3.1 Project Viability for the PPP partner
A base assumption for the project is that the weighted average cost of the power supplied to
the Municipality should not exceed the weighted average tariff paid by the Municipality for
electricity. The financial viability for the PPP partner is therefore calculated using the cost of
wholesale power for the Municipality as the upper bound of the price to be paid for power
under a future PPA.
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46
It is assumed that all the power generated will be used by customers connected to the grid
and not used locally by the EWS or other departments of the Municipality – in other words
the Project is seen as a direct displacement of wholesale power procured by the Municipality
rather than being wheeled to customers within the Municipality and displacing retail power
purchases.
Upper bound PPA price of electricity
The forecast average tariff is shown in the table below, based on the NERSA’s Multi-Year
Price Determination of 7 March 20198 for the increase in Eskom tariffs for the next two
years. The tariff is based on a weighted average tariff applicable to the solar PV projects with
the first year being based on the published Eskom tariffs as per the Eskom tariff book for
2019/20.
Table 9. Weighted Average Tariff for Solar PV
2019/20 2020/21 2021/22
Approved Tariff
Increases 8.10% 5.22%
Average Tariff for
Solar PV
Generation (c /
kWh)
102.0 110.3 116.1
Because the Eskom Megaflex tariff is a time of use tariff the average tariff is calculated based
on the time of day, including weekends, that the solar PV plants will be producing electricity.
It is also noted that the Municipality has confirmed that should there an agreement for the
purchase of electricity for these projects, it will be based on the kWh rates, i.e. only energy
supplied and will be in the time-of-use form as per the Eskom Megaflex tariff schedule.
It is also noted that future Megaflex tariffs are not known beyond the period of the NERSA
determination and as per discussions with the National Treasury the current Consumer Price
Index inflation rate of 4.5% is used in the base case model to escalate tariffs beyond that point.
An alternative approach is to use the recent history of Eskom tariff increases as a guide which
is a rate of 7.6% as shown in the table below. Eskom average tariffs have been increasing at a
rate faster than inflation over the recent past and the financial model allows for sensitivity to
future tariff inflation to be considered.
8 Issued as “NERSA’S Decision on Eskom’s Regulatory Clearing Account Application For Year 5 (2017/18) of the Third Multi-Year Price Determination and Eskom’s Fourth Multi-Year Price Determination for the Control Period of 2019/20 To 2021/22”
47
Table 10. Eskom average price increase path
Year Increase
2014 7.32%
2015 0.31%
2016 7.86%
2017 14.24%
2018 8.06%
2019 9.41%
2020
(approved) 8.10%
2021
(approved) 5.22%
Average 7.57%
Under a PPP approach the bidders will either need to select their own assumed tariff
escalation or the Municipality will need to determine a standard tariff escalation rate to be
applied to all bidders. Both approaches pose certain procurement and policy considerations
for the Municipality which are discussed further below. For the purposes of the feasibility
study, however, the above inflation rates have both been used as indicative values.
3.3.2 Project Capital Costs
The construction costs for a typical solar PV installation are based are based on recent costs
for similar projects and a typical breakdown of the different cost components is shown in the
figure below. The module costs are typically 50% of the total costs, followed by inverter costs,
balance of plant and substructure costs, as well as a 10% engineering, procurement and
construction margin. This may vary for each project depending on local site constraints and
design specificities.
The average full construction cost used in the initial technical assessment were:
sites above 300kWp was R14 264/kWp and;
sites smaller than 300kWp the cost was R16 141/kWp.
As there have been recent declines in capital costs of solar PV, and following discussion with
the Municipality, the financial assessment base case was conducted using lower cost
assumptions. The base case in the financial model uses costs of R11 578/kWp as an average
capital cost. It is suggested that these capital cost assumptions can also be tested during a
market sounding process. The financial model has also been structured to allow sensitivity
analysis to be easily conducted on the average capital cost.
48
Figure 3. Construction Cost Breakdown
A financial evaluation was performed for each of the 39 sites based on the outputs from the
yield studies and financial modelling parameters used in the simulations. From the results there
were eight sites which had a positive NPV. These are the eight largest sites and the NPV is
highest for these sites based on the economies of scale. The total capital cost for those
projects with positive NPV was estimated as approximately R68.3 million with a total capacity
of just over 5.0MWp.
Following further assessment one site (Glenwood 2 & 3 reservoirs) was removed from this
list due to the finding that there were heritage resources on the site that might prevent further
construction on site. This resulted in the base case in the financial model using the top seven
sites with a total capacity of just under 4.6MWp.
The full results are summarised across all the sites in the table below.
49
Table 11. Summary of Initial NPV Results
The following assumptions were used in the initial financial modelling in the technical study;
Average tariff = 83 c/kWh
Technical losses = 3%;
Inflation = 6%;
Annual degradation = 0.6%;
Project life = 20 years;
Operations and maintenance costs = 3% of capital cost;
Average Eskom price increase = 8.0% based on historical average price increase over
the past 5 years;
Discount rate = 10%.
The results of the analysis are displayed graphically in the figure below which shows the NPV
per site in order of installation size. The red line in the figure indicates the breakeven point,
i.e. where NPV = 0.
50
Figure 4. PV Plant Capacity vs NPV for Each Reservoir Site
For the smaller sites, i.e. those sites with installations < 300kWp, the NPV is negative on the
current assumptions. However, this could change depending on procurement options,
detailed engineering, price changes of solar PV equipment and so forth. Procuring in large
quantities could assist in reducing the overall cost and thus make more projects feasible.
3.3.3 Project Finance Model
Following the completion of the technical report and further engagement with the Municipality
a project finance model was prepared to allow consideration of the Project from the
perspective of a private PPP partner. The model allows for consideration of the impacts on
the inclusion of debt into the project as well as the operating costs of the project and other
factors and provides an indication of the IRR of the Project based on a 20-year PPA with the
Municipality.
As noted, some of the assumptions used in the technical analysis were updated in the financial
model due to changes since that report was prepared, including decreases in solar PV capital
costs as well as the NERSA tariff price determination for the 2019-2022 period. The updated
model also allowed the inclusion of new data, such as the costs of grid connection for the
identified sites provided by the eThekwini Electricity Department.
As there is uncertainty over some of the assumptions, for example the future tariff path of
wholesale electricity prices, the model allows for sensitivity analysis to be conducted on a
wide range of the input assumptions. This allows the Municipality to also test certain scenarios,
51
such as whether grid connection costs are borne by the PPP partner or the Municipality or
the impact of the inclusion of any capital grants that may be available for the Project. During
the preparation of the final procurement process it may be useful to use the model to test
the robustness of returns to the PPP partner.
The main model assumptions are shown in the table below.
Table 12. Key Project Finance Model Assumptions
INPUT VALUE UNIT
ESCALATION
Long Term Tariff Escalation 4.50% % / year
Operating Cost Escalation 4.50% % p.a.
TECHNICAL INPUTS
Capacity
4 590 MWp DC
Output
7 118 MWh / year
Performance Degradation 0.5% % / year
OPERATIONS
Starting Tariff
1
020.37 R / MWh
Surcharge 10.1% %
Management Cost per Site
120.00 R'000s / year
Number of Sites 7 No.
Site Management Costs 840 R'000s / year
Operating costs 1.25%
% of Capital
Costs
Insurance 0.75%
% of Capital
Costs
DEBT AND GRANTS
Grants 0% R'000s
Senior Debt Term
15 years
Debt Interest Rate 11.4% % / year
Upfront Bank Fee 2.0% % / year
Minimum Debt Service Cover Ratio
(DSCR)
1.25 ratio
Percentage Debt 60.0% %
52
INPUT VALUE UNIT
CAPITAL COSTS
Construction Period
9 Months
Capital Costs
53 144 R'000s
Grid Connection Costs
7 936 R'000s
Grid Costs PPP partner = 1 / Munic
= 0
1 flag
The inputs tabled above reflect the base case model. However, as noted, the model is sensitive
to some key assumptions. It is important to note that some of these assumptions cannot be
known, for example the views of a private PPP partner on future Eskom tariff increases. Other
assumptions are also hard to determine with accuracy, such as the capital costs of any
particular potential PPP partner bidder. However, there is reasonable confidence in the
assumptions as many are based on available secondary sources or based on discussions with
contractors, developers and financiers in the solar PV market who have provided indicative
information9.
The base case suggests that an equity IRR of c. 12.2% would be achieved on the above
assumptions. However, this return level is sensitive to some relatively conservative
assumptions, for example the base case assuming that the future escalation of Eskom tariffs
will be in line with current CPI inflation. If the recent trend of Eskom tariff increases is seen
as being indicative of continued above inflation increases in electricity tariffs a much higher
IRR results.
The graph below shows IRR sensitivity to different future tariff increase assumptions and
shows, for example, that at an assumed 6.5% increase in Eskom prices over the full PPA
period, an IRR of c. 15.4% would be achieved. If the average Eskom tariff increase between
2014 and 2021 of 7.6% is used for the future tariff path, then a 17.5% IRR is achieved.
9 This included requests for information or review of documentation of two solar PV EPC contractors, two 12J solar PV development companies and a development finance institution, as well as consideration of secondary sources. It is noted, however, that the EPC contractors indicated that costs can change relatively rapidly due to global prices in solar PV panels as well as foreign exchange movements. They also noted that firm pricing, in particular on ground-mounted PV, is relatively difficult for both capital and operating costs without examination of the ground conditions and locations.
53
Figure 5. Example: Sensitivity of Equity IRR to Future Tariff Escalation
The PPP partner returns are of course sensitive to capital costs and the inclusion or exclusion
of grid connection costs is material. If the Municipality were to bear the capital costs of the
grid connection, the equity IRR for the PPP partner would increase by about 4.7%, to a c.
16.9% return.
The sensitivity to capital costs of the PV plant itself is shown in the graph below. The analysis
suggests that a 25% reduction in estimated costs would increase IRR to 21.2%, while a 25%
increase in costs would reduce returns to all 6.4%, all else being equal.
Figure 6. Example: Sensitivity of Equity IRR to Capital Costs
The sensitivity to capital costs is indicative of the impact that any capital grants to the project
could have on its viability. Given the relatively low returns on the base case it is recommended
54
that the Municipality consider the application of available grants or other capital subsidies that
may be available through the national municipal grants system or from other sources.
It is also noted that since each site has a different grid connection cost each site will have a
different capital cost and hence a different return and financial viability if considered separately.
The Low Case scenario, used as the base case for the financial model, considers the seven
sites as a combined project and hence spreads the grid connection costs across the portfolio.
If each site were to be considered separately some sites, those where the grid costs are a
smaller percentage of total capital costs, would have greater financial viability than others.
3.3.4 Model as a tool
It is important to stress that the model is seen as tool and not as a provider of a single,
definitive output since the input assumptions will differ per private sector bidder; cannot be
fully known by the Municipality; will change from time to time depending on when the Project
is procured; and in some cases are under the influence or control of the Municipality itself.
It does appear, however, that at the base case the returns from the project may not be highly
attractive to the private sector, if the PPP partner will be required to fully absorb all the
ancillary costs of the project, particularly the grid connection costs which amount to 13% of
the total project capital expenditure.
3.3.5 Market Capability and Appetite
The Project is premised on the view that the private sector has the capacity and capability to
deliver the required project, as well as sufficient incentives to do so. In terms of capacity,
there is a rapidly growing solar PV supply market in South Africa, driven by the large-scale
government renewable energy procurement programme as well as by demand from
commercial, industrial and residential consumers. For example, the estimated installation of
rooftop PV just on retail malls is expected to reach approximately 700MW in 2018.
Table 13. Estimated Rooftop Retail PV Market Size
Reference: https://pqrs.co.za/data/apr-2017-shopping-centers-rooftop-and-pv-sales/)
There are now numerous companies capable of installing and operating medium to large PV
plants, including ground-mounted plants. The industry is also well organized, with an industry
association, the South African Photovoltaic Industry Association (“SAPVIA”) and growing
voluntary and mandatory standards. There is therefore little concern about attracting a
sufficiently reliable PPP partner that would deliver against anticipated technical targets.
55
The industry is also large enough and competitive enough to ensure good prospects for price
and quality competition under a competitive procurement process and similar processes from
the private sector for captive PV projects have seen meaningful bidder participation from the
private sector.
There are also growing numbers of locally owned solar PV developers and installers, including
many black-owned businesses and the industry should be able to meet the BBBEE or CPG
requirements of the Municipality. It is noted that while the local PV component manufacturing
and assembly industry is still relatively small, however the industry has in the past been able
to meet the National Treasury and DTI local content minimum thresholds imposed.
3.3.6 Ability to Meet Target Tariff
Given that a robust and competitive industry exists, the main consideration is whether the
target tariff can be met by a private provider at their required rates of return. Initial
discussions with service providers as well as the modelled returns suggest that the weighted
Megaflex tariff remains a difficult benchmark to achieve, especially in the eThekwini area
where solar radiation levels are somewhat lower than in the western and northern parts of
the country. This is borne out by the financial modelling which suggests that the project will
deliver IRRs that may be below the risk-adjusted rate of return that solar PV providers are
typically seeking in the market at present. Based on the private sector interviews it appears
that firms are seeking equity returns on project-financed small-scale PV project PPAs of
between 15% - 18%.
Whether the tariff is achievable by a private provider depends on a number of factors
including:
Length of PPA: the longer the PPA the more likely that the PPP partner can secure
long-term debt finance;
Bankability of PPA: the more “market friendly” the PPA the more likely that long-
term debt can be sourced, the lower the rates of this debt and the lower the risk and
hence return expectations from the private provider;
Risk Allocation: some key decisions around allocation of risk will determine the
ability of the PPP partner to meet the required tariff, these would include which party
takes the risk of future Eskom tariff increases, whether a flat or time of use tariff is
applied and so forth;
Bankability of off-taker: the eThekwini Municipality is likely to be seen as a credible
and bankable off-taker, but this can be influenced by the terms of the PPA, the
credibility of the PPP process and Council and National Treasury support and so forth.
Capital costs: these are generally decreasing over time but are subject to fluctuations
due to foreign exchange movements, global trade conditions and local content
requirements;
Site conditions: construction costs and plant generation are very dependent on local
site conditions for ground-mounted systems. For example, the slope of the ground,
requirements for more foundations than anticipated, shading and so forth can have a
relatively important impact on costs and forecast generation and hence tariff. Although
56
an initial site inspection has been undertaken these are at a relatively simple level. The
more information provided to the private sector, or the more allowance they have
for site inspections, the better able they will be able to price this risk.
There is little point in establishing a benchmark tariff that cannot realistically be met by the
private sector. This would be a waste of municipal time and resources and would damage the
Municipality’s reputation for future engagement with the solar PV sector.
It is therefore recommended that an Expression of Interest (“EOI”) process is carried out
prior to issuance of a Request for Proposals for final procurement. This EOI would be
designed to ascertain:
Industry interest at the benchmark tariff
Likely ability of the industry to secure the necessary finance
Industry views on key PPA terms that would best allow a tariff reduction
Industry views on the procurement approach
The EOI can be designed to be as broadly inclusive as possible and could include a meeting
with interested potential bidders to understand their views on the above matters.
3.3.7 Considerations of suitability for a PPP
The technical analysis shows that the Project would be technically suitable as a PPP. The
potential scale of the Project, even at the Low Case, would be a capital investment of
approximately R61 million (made up of R53.1 million for the plant and R7.9 million for grid
connection costs) and with annual revenues of approximately R8.6 million per year which
should be large enough to allow both the public and the private parties to achieve value-for-
money outputs given the likely levels of transaction costs.
The project outputs are easily specified, with the primary output being electricity exported
to the distribution grid which is measurable and directly translatable into a payment
mechanism. The technical outputs are also well understood and regulated and can be relatively
easily included in a technical specification for the Project and establishment of minimum
technical and health and safety standards.
The PPA can be structured to allow the bulk of the construction and operating risk, including
the risk of the solar resource itself, to the PPP partner, hence allowing a value for money
solution for the Municipality.
As noted, there is market capability and interest in these types of projects, however an
Expression of Interest process is recommended to ensure that the Project is commercially
viable at the tariff benchmark and under the envisaged procurement terms and in so doing to
further refine the precise size of the Project and the envisaged contractual terms and
conditions and the risk and cost allocation between the parties.
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4 PROJECT DUE DILIGENCE The Municipality intends to make a decision regarding a long-term contract with a partner in
order to generate renewable energy. To this end, this feasibility study intends to analyse the
possibility of this partnership taking the form of a public private partnership (“PPP”). The due
diligence report discusses the legislative framework within which a project of this nature must
operate, as well as identifying other due diligence items and risks that should be considered
prior to entering into a PPP.
4.1 Legal aspects
4.1.1 Relevant Legislation
Strauss Daly Attorneys have provided a legal review of key matters pertinent to the feasibility
study and the legislative review below is drawn largely from their review report which has
been provided to the EWS as a stand-alone report.
In the review Strauss Daly note that local government plays an important role in the electricity
industry in South Africa. Schedule 4B of the Constitution lists electricity and gas reticulation
as a local government responsibility. Section 153 of the Constitution places the responsibility
on municipalities to ensure the provision of services (which includes electricity reticulation)
to communities in a sustainable manner as well as promote economic and social development.
Electricity is an important funding source for local government, particularly for larger urban
municipalities.
The report further sets out the key legislation relevant to the Project:
The Municipal Systems Act (No. 32 of 1998) defines the roles of municipalities as service
authorities and assigns to municipalities the right to determine the service provider that will
distribute electricity within their boundaries. The Municipal Finance Management Act (No. 56
of 2003) outlines the requirements for municipalities to set tariffs for service provision,
including electricity tariffs.
Section 33 of the MFMA stipulates that a municipality can only enter into a contract imposing
financial obligations on the municipality beyond a three-year period if:
A draft of the contract is publicly advertised for comment 60 days prior to the
municipal council meeting at which the contract will be considered for approval.
The municipal council has considered the financial implications of the contract and any
comments received on the proposed contract.
The municipal council has adopted a resolution on the financial benefits of the contract
and authorised the municipal manager to sign the contract on behalf of the
municipality.
The Electricity Regulation Act (“ERA”) No. 4 of 2006 defines a ‘municipality’ as “a category
of municipality that has executive authority over and the right to reticulate electricity within
its area of jurisdiction in terms of the Municipal Structures Act” and deals substantially with a
58
municipality’s responsibilities in exercising its executive authority and duties.10 It also deals
with the selection and appointment of external service providers which establishes that a
municipality must comply with Chapter 8 of the Municipal Systems Act, the Municipal Finance
Act and the ERA prior to entering into a service delivery agreement with a service provider.11
Moreover, the Regulator must prescribe general key performance indicators in respect of the
technical operational issues pertaining to reticulation systems for municipalities.12
The New Generation Regulations of 2011 (published as GNR. 399 in Government Gazette
No. 34262 dated 4 May 2011) provide regulations targeted specifically at government
structures and outline the rules for the procurement and new generation capacity of
electricity by organs of state and are important for municipalities to take into account,
particularly if they are intending to procure electricity from an independent power producer
(IPP).
The aforementioned legislation provides municipalities with the authority to generate (where
applicable) and/or reticulate energy.13 This function includes the development of policies,
drafting by-laws, setting tariffs, deciding how energy reticulation services are provided and
regulating the provision of these services in terms of the by-laws and other mechanisms. Over
and above the energy reticulation mandate, there are also a number of regulations and rules
that provide guidance on how municipalities can deal with new generation in their areas of
control. The Municipality will have to be cognisant of these during the life-cycle of the project.
10 Section 27, “Each municipality must exercise its executive authority and perform its duty by -
(a) complying with all the technical and operational requirements for electricity networks determined by the Regulator;
(b) integrating its reticulation services with its integrated development plans;
(c) preparing, implementing and requiring relevant plans and budgets;
(d) progressively ensuring access to at least basic reticulation services through appropriate investments in its electricity infrastructure;
(e) providing basic reticulation services free of charge or at a minimum cost to certain classes of end users within its available resources;
(f) ensuring sustainable reticulation services through effective and efficient management and adherence to the national norms and standards contemplated in section 35;
(g) regularly reporting and providing information to the Department of Provincial and Local Government, the National Treasury, the Regulator and customers;
(h) executing its reticulation function in accordance with relevant national energy policies; and
(i) keeping separate financial statements, including a balance sheet of the reticulation business.
11 Section 28.
12 Section 29.
13 “Generator” in the ERA, means “a person who generates electricity” while “person” in the ERA is defined as, “any organ of state as defined in section 239 of the Constitution.”
59
As generation of electricity is not an automatic service or function provided by the
Municipality, Strauss Daly opine that it requires Council approval setting out the reasons as
to why the Municipality will be undertaking the responsibility of generating electricity as an
additional service and/or function within its power. This project may or may not take the
form of a PPP. If the PPP partner is going to perform a Municipal service or function, the
Municipality must first determine the need for that service or function and then determine
the best way to deliver the service or function. From the information received, it would seem
that the Municipality may be desirous of providing this additional service and/or function and
therefore, the Municipality must include in its feasibility what it would mean if the Municipality
provided the service or function internally versus externally (show best value for money). If
the feasibility study indicates that it should be done externally by a PPP partner, then a PPP
can be considered. In terms of a PPP, the PPP partner enters into a commercial transaction
with the Municipality, taking on considerable risk but with the opportunity of receiving a
benefit as a result of it providing the municipal service or function.
At the end of the project cycle, appropriate steps will have to be taken to ensure continued
delivery of the service or function. It may be possible that the Municipality does not wish to
render this additional service and/or function and in such a case, could, having assessed the
value and/or usefulness of its assets (land and/or otherwise) to be made available, to a PPP
partner following the Asset Transfer Regulations, rather enter into a long term lease with
separate PPP partner and/or Power Purchase Agreements (‘PPA’). This would require public
participation and a proper bidding process to determine the best offer (which must be at
market value)14.
The premise of this feasibility study is that the Municipality, via the EWS, does want to deliver
renewable energy within its jurisdiction and the study has therefore carried out the
investigation of the appropriate structure of a PPP, with the conclusion that a PPP structured
via a PPA is a feasible outcome which, with the correct design and procurement, can offer
value to money to the Municipality.
A first legislative filter is whether the municipality has the institutional authority to conclude
a PPP with a PPP partner for purposes of the generation and purchase of electricity or whether
the municipality is precluded from doing so by virtue of the exclusive competence on the part
of the municipality to carry out such activities.
Local government legislation differentiates between municipal services and municipal support
activities.
A municipal service is a service that “a municipality, in terms of its powers and
functions, provides or may provide to or for the benefit of the local community
irrespective of whether: (a) such service is provided by the municipality through an
internal mechanism or by engaging an external mechanism and (b) fees, charges or
tariffs are levied in respect of such service or not.”
A municipal support function is defined as “an activity that is reasonably necessary for
or incidental to the effective performance of a municipal function and exercise of its
powers that does not constitute a municipal service.”
14 Section 33 to 36 of the Asset Transfer Regulations.
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Electricity distribution is a municipal service however the purchase or generation of electricity
is not. It is not definite that the purchase of electricity is a municipal support function, rather
than simply a bulk purchase, but arguably it could be seen to be such.
The MFMA is the relevant legislation that will need to be complied with when a municipality
intends to utilise a PPP for the procurement of a private partner to assist with municipal
support activities. In this regard, the procedure to be followed differs from, and is less
stringent than, that procedure pertaining to the procurement of a private partner to perform
a municipal service, as contained in the MSA.
The legislative framework therefore does appear to make provision for the use of a PPP in
order to execute embedded power generation by a PPP partner. The selection of a PPP as
the manner in which this municipal support activity is to be provided, will however, require
substantiation.
Section 33 of the MFMA deals with contracts having future budgetary implications beyond the
three-year budget period of a municipality. As the intention of the PPP is to enter into a 20-
year PPA with a PPP partner the PPA will be subject to approval in terms of Section 33.
The accounting officer may not sign a long-term PPP agreement unless section 33 of the
MFMA has been complied with.
Section 33 (1) (a) of the MFMA requires a minimum 60-day period prior to the council meeting
at which the PPP agreement is to be considered. During that 60-day period, the municipality
is required to make public the particulars of the proposed PPP agreement and to solicit
comments from the local community. In addition to the public notification, publication of
documents and written comments, the municipality must also solicit the views and
recommendations of the National Treasury, COGTA and the DOE.
Within the 60-day period, the municipality must receive the public comments and views and
recommendations of the relevant government bodies and process these comments in time
for the council meeting at which the PPP agreement will be considered.
The below extract from section 33 of the MFMA sets out the key factors that the municipal
Council must take into account before entering into a long-term contract:
S33(1) (b) the municipal council has taken into account –
(i) the municipality’s projected financial obligations in terms of the proposed contract for each
financial year covered by the contract;
(ii) the impact of those financial obligations on the municipality’s future municipal tariffs and
revenue;
(iii) any comments or representations received from the local community and other interested
persons; and
(iv) any written views and recommendations on the proposed contract by the National
Treasury, the relevant provincial treasury, the national department responsible for local
government and any national department referred to in paragraph (a) (i) (cc); and
This feasibility report contains the required information needed to be taken into account by
the Municipal Council in making the decision to enter into the PPP contract, aside from the
consultation components.
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4.1.2 Electricity Regulation Act
The proposed activities are exempt from the requirement to apply for and hold a licence
under the Electricity Regulation Act 4 of 2006 (“ERA”). The act states that no person may,
without a license issued by the National Energy Regulator of South Africa (“NERSA”), operate
any generation facility. However, exemptions to this licensing were introduced in an
amendment to the ERA which was issued under Government Gazette No. 41237 of 10
November 2017. The effect was to amend Schedule 2 of the ERA which relates to exemptions
of certain activities from having to obtain an electricity generation licence, in terms of section
7 of the ERA.
Exemption 1 applies to a national grid-connected generation facility with an installed capacity
which is no more than 1MW, where:
Electricity is supplied to a single customer and there is no wheeling through the
national grid;
The generator or single customer has entered into a connection and use-of-system
agreement, or obtained approval from the distributor, and
When the connection and use of system agreement or approval is obtained the
minister has not published a notice in the Government Gazette that the allocated
amount of MW in the IRP for embedded generation of this nature has been reached.
In the proposed project the above criteria will be met as the project owner will be an
Independent Power Producer (“IPP”) and will enter into a connection and use-of system
agreement with the eThekwini Electricity Department. The eThekwini Municipality will be the
single customer of the project and of each facility.
The Minister has also not published a notice stating that the allocated MW in the IRP for solar
PV embedded generation has been met. Each facility will be a grid-connected facility smaller
than 1MW in capacity.
There are further proposed amendment of the ERA Schedule 2 which were published on 8
June 2018, however these are not yet promulgated into law and would not affect the
generation licensing requirements of the project.
Although each site will have a separate installation of less than 1MW and a separate
connection point, there is the potential that NERSA could deem the entire portfolio a single
project if there is a single use-of-system agreement with the Municipality or a single PPA. It is
therefore recommended that NERSA is approached to understand their view on this issue. If
there is remaining uncertainty there may be the requirement for further legal advice on
whether NERSA can legally adopt such a stance and if so, whether this could be addressed
through an appropriate project structure such that each site is legally separate and is
contracted via a separate PPA and connection and use-of system agreement.
NERSA’s objectives are set out in Regulation 10 of GN R. 721 GG No. 32378 of 5 August
2009 under the ERA: Electricity Regulations on New Generation Capacity, whereby NERSA
has prepared Rules which will affect the recovery of power purchase costs falling under the
ERA. These objectives provide valuable context to NERSA’s ultimate goals. In terms of the
regulations, NERSA is directed to:
“achieve the efficient, effective, sustainable and orderly development and operation of
electricity supply infrastructure in South Africa;
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ensure that the interests and needs of present and future electricity customers and
end users are safeguarded and met, having regard to the governance, efficiency,
effectiveness and long-term sustainability of the electricity supply industry within the
broader context of economic energy regulation in the Republic;
facilitate investment in the electricity supply industry;
facilitate universal access to electricity;
promote the use of diverse energy sources and energy efficiency;
promote competitiveness and customer and end user choice; and
facilitate a fair balance between the interests of customers and end users, licensees,
investors in the electricity supply industry and the public."15
The Strauss Daly review notes that these interests should be borne in mind during the
conclusion of the PPA and during any discussions with NERSA on the basis of exemptions
held under Schedule 2 of the ERA. The review notes that essentially, the project ultimately
enables NERSA to fulfil each of the aforementioned objectives.
NERSA registration
Although a generation license is therefore likely not required, registration of the systems
with the licensed Network Service Provider, i.e. the Municipality itself, and NERSA remains a
requirement. Section 9(2) of the ERA stipulates that any person who has to register with the
Regulator must do so in the form and in accordance with the prescribed procedure, and an
application for registration must be accompanied by the prescribed registration fee. This
registration process would need to be undertaken by either the PPP partner or the
Municipality on behalf of its PPP partner once the project was implemented.
4.1.3 Environmental Authorisation and Management
SA-LED conducted an assessment to of whether the activities contemplated required an
Environmental Impact Assessment (“EIA”) and authorisation under the National
Environmental Management Act No. 107 of 1998 (“NEMA”). This assessment was mainly
informed by the Department of Environmental Affairs (2015) EIA Guideline for Renewable
Energy Projects16.
The table below presents an assessment of potential listed activities in terms of the EIA
Regulations, 2014 that can possibly trigger a Basic Assessment (“BA”) and compares these
against the project activities to determine applicability.
15 Objectives in terms of GNR.119 of 24 February 2010: Regulatory Rules for Power Purchase Cost Recovery (Government Gazette No. 32964).
16 GNR 989 of 16 October 2015, Government Gazette 39297; Guideline on EIAs for Renewable Energy Projects.
63
A fuller assessment has been conducted against all the listed activities but only those
potentially applicable are shown below. These include activities in Listing Notice 1 as well as
Listing Notices 2 and 3.17
Table 14. Evaluation of Activities Against NEMA Basic Assessment Activities List
Activities that require a Basic Assessment Applicability to this
Project
Activity 1:
The development of facilities or infrastructure for the
generation of electricity from a renewable resource where –
(i) the electricity output is more than 10 megawatts but less than
20 megawatts; or
(ii) the output is 10 megawatts or less but the total extent of
the facility covers an area in excess of 1 hectare;
excluding where such development of facilities or infrastructure
is for photovoltaic installations and occurs within an urban area.
Not applicable
Output <10MW
Three sites may be >
1ha in extent but the
installation is PV and
does occur within an
urban area
Activity 11:
The development of facilities or infrastructure for the
transmission and distribution of electricity –
(i) outside urban areas or industrial complexes with a capacity
of more than 33 but less than 275 kilovolts; or
(ii) inside urban areas or industrial complexes with a capacity of
275 kilovolts or more.
Technologies
Not Applicable
Within urban area
** municipality to
confirm the
connections will be
<275kv
Activity 27:
The clearance of an area of 1 hectares or more, but less than
20 hectares of indigenous vegetation, except where such
clearance of indigenous vegetation is required for –
(i) the undertaking of a linear activity; or
(ii) maintenance purposes undertaken in accordance with a
maintenance management plan.
Not Applicable
The sites are already
cleared for the
purposes of
reservoir
maintenance
Activity 36:
The expansion of facilities or structures for the generation of
electricity from a renewable resource where–
Not Applicable
The sites are all
<10MW
17 See GNR.982 of 4 December 2014: Environmental Impact Assessment Regulations, 2014 (Government Gazette No. 38282) as well as Environmental Impact Assessment Regulations Listing Notice 1 of 2014 GN R983 in GG 38282 of 4-12-2014 as substituted by GNR.327 of 7 April 2017 (basic assessment, provincial); Environmental Impact Assessment Regulations Listing Notice 2 of 2014, published under Government Notice No.984 in Gazette No.38282 on 4 December 2014 (S&EIR or full assessment); Environmental Impact Assessment Regulations Listing Notice 3 of 2014 GN R985 in GG 38282 of 4-12-2014 as substituted by GNR.324 of 7 April 2017 (basic assessment national).
64
Activities that require a Basic Assessment Applicability to this
Project
(i) the electricity output will be increased by 10 megawatts
or more, excluding where such expansion takes place on
the original development footprint; or
(ii) regardless the increased output of the facility, the
development footprint will be expanded by 1 hectare or
more;
excluding where such expansion of facilities or structures is for
photovoltaic installations and occurs within an urban area.
The development
footprint is not being
expanded
Activity 47:
The expansion of facilities or infrastructure for the transmission
and distribution of electricity where the expanded capacity will
exceed 275 kilovolts and the development footprint will
increase.
Not Applicable
Within urban area
** municipality to
confirm the
connections will be
<275kv
LISTING NOTICE 2 - Activities that require a Basic
Assessment in terms of regulations 19 and 20 of the
Environmental Impact Assessment Regulations18
Activity 12:
The clearance of an area of 300 square metres or more of
indigenous vegetation except where such clearance of
indigenous vegetation is required for maintenance purposes
undertaken in accordance with a maintenance management plan
in KwaZulu-Natal in:
i. Trans-frontier protected areas managed under
international conventions; Community Conservation
Areas;
ii. Biodiversity Stewardship Programme Biodiversity
Agreement areas;
iii. Within any critically endangered or endangered
ecosystem listed in terms of section 52 of the NEMBA
or prior to the publication of such a list, within an area
that has been identified as critically endangered in the
National Spatial Biodiversity Assessment 2004;
iv. Critical biodiversity areas as identified in systematic
biodiversity plans adopted by the competent authority
or in bioregional plans;
v. Within the littoral active zone or 100 metres inland from
high water mark of the sea or an estuarine functional
Potentially applicable
Require Municipal
input in order to
determine
applicability;
Clearance of an area
of 300 square metres
or more of
indigenous
vegetation may apply
in this case.
18 GNR.982 of 4 December 2014: 2014 (Government Gazette No. 38282).
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Activities that require a Basic Assessment Applicability to this
Project
zone, whichever distance is the greater, excluding where
such removal will occur behind the development setback
line on erven in urban areas;
vi. On land, where, at the time of the coming into effect of
this Notice or thereafter such land was zoned open
space, conservation or had an equivalent zoning;
vii. A protected area identified in terms of NEMPAA,
excluding conservancies;
viii. World Heritage Sites;
ix. Sites or areas identified in terms of an international
convention;
x. Areas designated for conservation use in Spatial
Development Frameworks adopted by the competent
authority or zoned for a conservation purpose;
xi. Sensitive areas as identified in an environmental
management framework as contemplated in chapter 5 of
the Act and as adopted by the competent authority; or
xii. In an estuarine functional zone.
LISTING NOTICE 3 – Activities that require a Full
Assessment in rerms of Regulations 21 to 24 of the
Environmental Impact Assessment Regulations19
Activity 1:
The development of facilities or infrastructure for the
generation of electricity from a renewable resource where the
electricity output is 20 megawatts or more, excluding where
such development of facilities or infrastructure is for
photovoltaic installations and occurs within an urban area; or on
existing infrastructure.
Not applicable
Output <10MW
Activity 2:
The development and related operation of facilities or
infrastructure for the generation of electricity from a non-
renewable resource where the electricity output is 20
megawatts or more.
Not applicable
Output <10MW
Activity 9: Potentially Applicable
19 GNR.982 of 4 December 2014: 2014 (Government Gazette No. 38282).
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Activities that require a Basic Assessment Applicability to this
Project
The development of facilities or infrastructure for the
transmission and distribution of electricity with a capacity of
275 kilovolts or more, outside an urban area or industrial
complex excluding the development of bypass infrastructure
for the transmission and distribution of electricity where such
bypass infrastructure is —
1. temporarily required to allow for maintenance of
existing infrastructure;
2. 2 kilometres or shorter in length;
3. within an existing transmission line servitude; and
4. will be removed within 18 months of the
commencement of development.
Require additional
factual information in
order to determine
applicability;
Output <10MW
It thus appears that a BA is not required for the project under the EIA regulations.
The project involves installation of solar PV panels on already developed reservoir sites. There
is little to no maintenance required for solar PV and the components of the systems are
mostly chemically inert limiting the potential of it being a source of contaminants to the
environment.
There are nevertheless some possible negative environmental impacts envisaged from the
project. As most of the reservoirs are located in residential areas the potential environmental
and social impacts are associated with the construction phase of the projects. These potential
impacts are discussed below:
Noise pollution: During the construction phase there is likely to be noise pollution due
to the heavy machinery used. However, no noise emissions are expected during the
operation phase of the solar PV panels.
Impacts on biodiversity: There is little natural vegetation in the reservoir areas. And it is
envisaged that there would be no requirements to clear any undisturbed vegetation
for the access of machinery and installations.
Light or heat reflection: Solar PV panel surfaces are smooth and reflective and can reflect
light based on their tilt of the panel and time of day. In situations where such reflection
affects neighbours this is most likely a source of grievances. It is important to note
that the reflection of light from the PV panels could also pose a threat for the airplanes
that operate in the area. To minimise the effect of reflection the tilt of the solar PV
panels could be adjusted in particular circumstances where nuisance could be caused.
The developer could consider not using mirror material to prevent the formation of
specular reflection caused by light pollution nuisance.
Chemical pollution: Chemical pollution is not often associated with the use of the solar
PV panels. It is important to have a waste management plan that would address the
handling and management of solar PV waste which is considered to be hazardous e-
waste. This will mainly be a concern during decommissioning and disposal of the solar
PV panels.
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Reservoir contamination: As the plants will be co-located with the municipal reservoirs
consideration will need to be given to the potential for water contamination. Although
this appears to be unlikely it should be included as a potential risk for consideration.
Waste: Most of the waste associated with this project is likely to be generated during
the installation phase and the decommissioning of the systems. The solar panels need
to be considered as e-waste and should be treated as hazardous waste. This waste will
need to be contained and stored in appropriate locations before it is re-used, recycled
or sent to final disposal. The project will need to develop and implement a waste
management plan for this phase.
Possible social impacts to be considered:
Disturbance during construction: The solar PV installations will take place in some
residential areas and the main social impacts typical of a small construction project
would be expected during the construction phase. To minimise the impact and get
buy-in from residents it is important that these issues are managed in a systematic
manner. EWS and the developer will have to provide information to the public on the
projects and their work schedules and take into account local circumstances.
Occupational Health and Safety: During the construction of a solar PV project heavy
equipment is usually used. This raises chances of accidents during such a project. To
minimise such risks the project developer and EWS should ensure that all workers
are provided and equipped with fully functional personal protective and safety
equipment. The project developer will have to ensure that heavy duty equipment in
use are safe and are regularly maintained.
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Environmental management plan
While an EIA is not a requirement the PPP partner, in conjunction with EWS, will have to
develop an environmental management plan to introduce environmental strategies for
minimising or managing the inevitable environmental impacts. The management plan should
cover different phases of project development:
Pre-construction phase;
Construction phase;
Post-construction phase (operations and decommissioning).
Other potential environmental impact mitigation measures for the project could include the
following:
Conducting pre-disturbance surveys as appropriate to assess the presence of sensitive
areas, fauna, flora and sensitive habitats;
Plan visual impact reduction measures such as natural (vegetation and topography) and
engineered (berms, fences, and screens);
Site projects to avoid construction too near pristine natural areas and communities;
Ensure that the preferred reservoirs are not close to important habitat for faunal
species, particularly species which are threated or have restricted ranges, and are
collision-prone or vulnerable to disturbance, displacement and/ or habitat loss;
Utilise existing roads and servitudes as much as possible to minimise project footprint;
Fence sites as appropriate to ensure safe restricted access;
Ensure dust abatement measures are in place during and post construction.
The environmental management plan should be accompanied by a well-defined monitoring
plan. This will ensure that the suggested management plan is under-taken, and the objectives
of the project is being achieved.
It is recommended that either internal environmental management staff or a suitably qualified
external consultant undertake a rapid risk assessment and prepare a simple environmental
management plan that the PPP partner would need to implement and abide by. This plan
would be included as part of the technical requirements under the procurement process.
Additional Authorisations
The legal review notes that in addition to the environmental authorisation requirements
under the National Environmental Management Act 107 of 1998 (“NEMA”) the following
authorisations may need to be obtained under the relevant legislation in order to establish
and operate a solar power plant20:
20 The Strauss Daly report should be consulted for further details on the possible further assessments and authorisation processes required regarding: heritage approvals, land-use authorisations, municipal building plan approval, municipal permits, and biodiversity consents – including Provincial government requirements.
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Heritage impact assessment (usually undertaken as part of the environmental impact
assessment process) and approval of the heritage authorities under the National
Heritage Resources Act 25 of 1999 (NHRA) ;
Water use licence under the National Water Act (NWA);
Consent under the Subdivision of Agricultural Land Act 70 of 1970 (SALA) for the
registration of long leases and/or servitudes over agricultural land or the subdivision
of agricultural land;
Land use authorisations under provincial and national legislation;
Building plan approval; and
Various permits to undertake activities that may negatively affect threatened or
protected species.
Regulatory matters
4.1.4 Grid Code Requirements
In addition to the electricity generation licensing regulations, a number of specific technical
grid code requirements will need to be met by the solar PV installations. Some of these
specifications are still under development. These include:
NRS 097 –1: XXXX Part 1: Embedded generators to MV and HV for systems ≥100
kVA (Planned)
NRS 097-2-1: Grid interconnection of embedded generation – Part 2: Small-scale
embedded generation – Section 1: Utility interface.
NRS 048-2: Electricity supply – Quality of supply – Part 2: Voltage characteristics,
compatibility levels, limits and assessment methods.
NRS 048-4: Electricity supply – Quality of supply – Part 4: Application practices for
licencees.
Grid Connection Code for Renewable Power Plants (RPPs) connected to the
electricity Transmission System (TS) or the Distribution System (DS) in South Africa,
Version 2.6, November 2012.
The eThekwini Electricity Department may also have further technical requirements for
connection to the municipal distribution grid. These requirements will need to be included in
any procurement technical specifications.
4.2 Use rights and Site Enablement
As the project infrastructure will be established on land owned by the Municipality a land
availability agreement will need to be entered into between the Municipality and the PPP
partner. This agreement will need to be for the same period as the PPA and can be at a
nominal value. The agreement will need to provide for the relative rights and responsibilities
of the Municipality regarding the sites.
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4.2.1 Site enablement
Prior to entry into the land availability agreement the Municipality should review whether
there are any legal limitations on the use of the property, whether the Municipality have the
required title deeds and whether any planning permission is required. Specific considerations
to be reviewed include:
Confirmation by the Electricity Department of sites suitable for grid connection;
Verification and compilation of any approvals required;
Confirmation of land ownership and any title deed endorsements or lease interests
on the sites;
Confirmation that there are no pending land claims;
Compliance with zoning rights, town planning requirements and the IDP.
Based on the market testing the Municipality should determine to what degree site risks are
to be allocated to the PPP partner.
In particular, the issue of geo-technical risks and site conditions will influence the interest and
ability of private parties to effectively bid. An initial set of site condition requirements to be
considered are tabled below:
Table 15. Site Condition Requirements and Considerations of Allocation of
Responsibility
Site Condition Who
Responsible
When
Sufficient ground at adequate
gradients
EWS Prior to procurement
Shading EWS and / or
PPP partner
EWS – assess prior to
procurement
PPP partner – ongoing
clearing of shading
vegetation
Perimeter fencing EWS Prior to construction
Ongoing through project
Security and Access Control EWS and PPP
partner Prior to construction
Ongoing through project
Ground conditions for solar
structures
PPP partner Prior to bid submission
Site clearing PPP partner Prior to construction
In the refinement of the project definition the EWS will need to identify the specific site
conditions to be determined prior to procurement and construction and identify who is
responsible and at what stage in the establishment process.
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4.3 Socio-economic and BBBEE
The Municipality may desire or be required to include additional socio-economic objectives
and considerations into the design and structure of the Project.
4.3.1 Broad-Based Black Economic Empowerment and Socio-Economic
Requirements
As noted, the Municipality has confirmed that the procurement of the Project will need to be
in accordance with the Contract Participation Goals (“CPG”) as per the Municipal supply
chain management guidelines. These goals will therefore need to be included in any RFP to be
issued and any associated obligations on the PPP partner included in contract documentation.
4.3.2 Local Content Requirements
The National Treasury and the DTI have published local production and content requirements
for the municipal procurement of solar PV systems. These have been published under the
Preferential Procurement Regulations 2011 pertaining to the Preferential Procurement Policy
Framework Act, Act No 5 of 2000. Regulation 9 (1) prescribes that in the case of designated
sectors bids must be advertised with the specific bidding conditions that certain minimum
thresholds for local production and content for certain goods and services. The DTI has
determined these thresholds for solar PV systems and these have been issued under the
“National Treasury Designated Sectors Instruction Number 2 of 2016/2017 – Invitation and
Evaluation of Bids Based on Stipulated Minimum Threshold for Local Production and Content
for Solar Photovoltaic System and Components.”
The specific local content requirements are tabled below.
Table 16. National Treasury Designated Sectors Instruction for local production
and content for Solar PV
Solar PV
Components
Minimum
Local
Content
Threshold
Conditionality
Laminated PV
modules
15% The local process will include tabbing & stringing of
cells, encapsulation and lamination, final assembly and
testing in compliance with IEC standards
Module Frame 65% Aluminium Components: All Aluminium PV Module
Frames, PV mounting structures, clamps, brackets,
foundation components and fasteners are to be
manufactured from locally produced extruded, rolled
cast or forged products
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Solar PV
Components
Minimum
Local
Content
Threshold
Conditionality
DC Combiner
Boxes
65% DC Combiner Boxes: Enclosures must be made from
SMC and moulded in South Africa
Mounting
Structures
90% All aluminium PV Module Frames, mounting
structures/racks, clamps and fasteners are to be
manufactured from locally produced extruded, rolled,
cast or forged products
Inverter 40% Must be assembled locally
As per the National Treasury instruction, bids in respect of solar PV systems and components
must contain a specific condition which states that “only locally manufactured solar PV system
and components with a prescribed minimum threshold for local production and content will
be considered”.
4.4 Accuracy of measurements and recordings in feasibility study
The measurement processes of the site conditions and the assumptions underpinning the
technical performance and costs of the project have been outlined in the relevant sections of
the report. These measurements are appropriate to this stage in the feasibility study process.
It is noted, however, that there may be site specific ground conditions that affect final project
costs and further evaluation of these, or the passing of ground risk to the PPP partner, is
recommended.
4.5 General Due Diligence Considerations
The main risks related to the project are noted in the table below. Considerations as to the
allocation of the risk between the Municipality and PPP partner via contractual conditions or
other mechanisms are outlined in the table. The Municipality will need to decide the level of
risk transfer with the broad principle being that the greater the transfer of risk to the private
partner, the higher the electricity tariffs offered are likely to be.
Table 17. Due diligence and risk transfer considerations
Contractual
Commitments
Potential Risks or Contingent
Liability
Proposed Mitigation and Risk
Allocation
Technical and
Operational
Performance
Grid connection The Municipality Electricity
Department will take contractual
Technical review of all sites to be
undertaken by the Electricity
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Contractual
Commitments
Potential Risks or Contingent
Liability
Proposed Mitigation and Risk
Allocation
responsibility for the connection
of the various installations to the
municipal grid.
Department prior to final project
design.
In particular, the substation
capacity, feeder bay, connection
voltage and capacity needs per
site will must be confirmed by
the Electricity Department.
Electricity Department to
confirm that the connection
costs will be borne by the
Electricity Department and that
the required budget and
technical resources are in place.
Environmental Environmental damage on site
from construction, operations or
decommissioning of the PPP
partner.
Full pass-through of
environmental liability to the PPP
partner under the PPA or
associated PPP agreement.
Health and safety Health and safety risks of an
embedded power generator in
the distribution grid.
Suitable technical requirements
to be met by the PPP partner
including all requirements of the
Electricity Department and
national grid code and embedded
generator standards.
Electricity Department and or
independent engineer to confirm
that suitable grid protection and
safety standards are in place
prior to commissioning.
Cultural and
Environmental
Failure to undertake Heritage
Impact Assessment
The heritage resources authority,
Amafa aKwaZulu-Natali Heritage
Council and the eThekwini
Metro Heritage forum are
notified of the proposed
development together with a
comprehensive report of each of
the potential sites.
Land Use
Planning
Failure to obtain Land Use
Authorisations
Site appropriate land
development applications must
be submitted to the relevant
authority.
Land Use
Planning Lack of Municipal building plan
approval
Building plans must be submitted
and approved in accordance with
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Contractual
Commitments
Potential Risks or Contingent
Liability
Proposed Mitigation and Risk
Allocation
the National Building Regulations
and Building Standards Act
Land Use
Planning
Failure to obtain Municipal
Permits
Wherever Municipal permits are
required, the bylaws must be
reviewed and applications made
in terms thereof.
Environmental Failure to obtain Biodiversity
Consents
Employ services of registered
environmental practitioner and
undertake an assessment of each
potential site upon which a
generation facility is planned to
be constructed in order to
ascertain whether there is a
potential risk to biodiversity.
Financial
Price Risk of non-compliance with the
Electricity Department policy to
that purchase prices are capped
at the rates at which the
Department buys power from a
bulk services provided within an
organ or state.
The PPA electricity purchase
price will be capped at Megaflex
energy rates (275kV).
Note this passes considerable
price inflation risks onto the PPP
partner.
Take or pay off-
take
requirements
Requirement to purchase all the
power produced and risk that
more power is produced than the
Municipality needs.
The total projected output of the
project is well under 1% of total
power demand of the
Municipality and therefore all
power generated and purchased
will be able to be distributed and
sold. Municipality to retain this
risk.
Deemed energy Risk that due to grid outages due
to national load shedding or local
grid instability or maintenance
lead to the purchase of deemed
power that cannot be used or
sold
PPA structure that provides for a
threshold percentage of grid
availability below which there is
no deemed energy to be paid to
the PPP partner.
The higher this threshold the
greater the risk that the PPP
partner takes and is likely to
price into the tariff.
Contractual
Site conditions Risk that the ground conditions or
other conditions of the selected
sites are not suitable for the PV
Proposed that there is a
procurement process that allows
bidder inspection of the sites and
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Contractual
Commitments
Potential Risks or Contingent
Liability
Proposed Mitigation and Risk
Allocation
plant construction or that they
increase the costs of construction.
This will in turn increase the
likelihood of contractual disputes
with the PPP partner.
that the ground risk is passed to
the PPP partner.
Site security Risk that plant equipment is lost or
damaged due to illegal access to
the sites.
As the sites are owned and
controlled by the Municipality it
appears that site security and site
management risk is best allocated
to the Municipality. However, the
Municipality may consider
insuring against this risk.
Alternatively, site security
requirements can be passed to
the PPP partner but this will likely
increase PPP partner tariffs
offered.
It does not appear that there are any implications of the proposed PPP approach for municipal
employees. The displacement of a small percentage of the Municipality’s bulk electricity
purchase will not affect employment within the municipal Electricity Department.
The Municipality has confirmed that there will be no changes in the scope of work of current
EWS workers on the site or any other labour arrangements with site management
responsibilities being undertaken by the PPP partner.
The envisaged PPP partner approach is likely to lead to an increased employment, at least
temporarily, in the construction phase of the project and will lead to additional employment
by the PPP partners during operations for such activities as panel cleaning and more technical
site operations.
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5 SERVICE DELIVERY ANALYSIS The identified service, locally generated renewable energy could potentially be provided
through various service delivery options from a range of institutions. A brief evaluation of
these options is tabled below:
Table 18. Service delivery analysis
Institutional
Option
Budget Competence Experience
Municipality Insufficient capital
budget due to
alternative capital
demands in the
electricity sector
Electricity
Department has
sufficient
competence to
procure solution.
May lack operational
skills.
Very limited
experience in design,
construction,
operations and
maintenance of
ground-mounted PV
Municipal Entity No applicable Municipal Entity currently in place with the required
competence and experience and project too small to warrant
establishment of a new entity
Adjacent
Municipality
eThekwini has greater budgetary resources and internal capacity
than smaller adjacent municipalities
Organ of State Possible options would include Eskom and Central Energy Fund
but neither currently implement small-scale local renewable energy
projects
Private Sector Current rapid
expansion of
privately developed
and financed solar
PV projects in the
corporate and
industrial space
indicate sufficient
financial resources
to fund projects of
this scale
Extensive
competence in a
range of small,
medium and large-
scale solar PV
companies through
the value chain.
Rapidly growing
market of 100s of
MW of rooftop and
ground-mounted PV
installed at the
distribution level
and numerous utility
scale plants
developed and built.
Based on the brief analysis it appears that the Municipality would likely have the internal
competence to procure a solar PV project of the envisaged size, possibly with external advice
on specific aspects such as project design. However, the Municipality has indicated that it is
constrained by the unavailability of sufficient capital resources for the project.
Given this capital constraint, the most appropriate alternative service delivery option is the
private sector which has demonstrated competence and experience in the sector as well as
demonstrated ability to raise the necessary capital for such projects.
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If the private sector were to be used as a delivery partner it would be possible for the
Municipality to address other social objectives, such as BEE and skills transfer to municipal
staff, through the conditions of the procurement and PPP contract.
5.1 Proposed PPP Type
Section 120 of the MFMA and the Municipal PPP regulations cater for a wide variety of PPP
types.The Guidelines distinguishes between three basic types of PPP, two involving the
performance of a municipal support activity or the delivery of a municipal service and the
other involving ‘the use of state property to generate revenue for the municipality. In a service
delivery project, the institution sets service delivery objectives and pays the PPP partner for
the service, usually in the form of a constant unitary payment or the users pay. In PPPs
involving the use of state property, an institution’s assets such as land are used to generate
revenue for the institution.
Although under the envisaged project the private partner will be using the Municipality’s land,
the proposed PPP falls more clearly under the delivery of a service. It should be noted that
this is not the delivery of the municipal service of electricity reticulation itself, but rather the
provision of an input into this service, that being the purchase of electricity.
5.1.1 Proposed PPP project structure and sources of funding
The proposed PPP structure is for the Municipality to contract with a PPP partner under a
long-term Power Purchase Agreement (“PPA”) under which the PPP partner would assume
the full financing, construction and operations of the proposed project. The project itself
would be defined as a number, to be determined, of separate solar PV plants located on
Municipal reservoir sites and providing power into the local distribution grid.
The PPP partner would be a private sector partner in the PPP and would assume the full
construction and operations risk of the project. The Municipality would provide the land for
the project and would retain the risk of the long-term purchase of power from the project at
a contracted tariff under the PPA. The Municipality would also assume other risks typical of a
PPA structure, for example the payment of deemed energy provision in the event that the
Municipality was not able to accept the electricity generated.
The Municipality would provide the funding for some aspects of project development, such as
the determination of technical specifications, and social and environmental requirements, as
well the transaction costs associated with the procurement process and legal costs. The PPP
partner would provide the full capital costs and it is assumed that the PPP partner is likely to
raise these costs via a combination of equity and debt from commercial banks or development
finance institutions.
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5.1.2 Payment mechanism
The payment mechanism would be a unitary payment per kWh of electricity generated (“the
tariff”) and provided to the local grid and would be governed by a PPA between the PPP
partner and the Municipality.
The amount of the payment would be determined via a competitive tender under which the
key tender evaluation criterion would be the tariff, subject to meeting the technical criteria
and subject to any adjustment for BBBEE. The tariff cap would be determined by Municipal
policy and currently would therefore be capped at the current amount paid by the Municipality
for its bulk electricity supply from Eskom, plus a surcharge determined by the Electricity
Department which takes into account the value of local generation due to avoided network
power losses. The PPA would include suitable provisions for the annual escalation of this tariff.
As a single good is being provided, that being kWh’s of electricity, and not, for example, power
availability services, a single unitary payment can be used and no splitting of the payment
between services is envisaged.
The PPA would govern the key areas of performance. The PPP partner would need to
maintain certain technical specifications to avoid interference of the local grid and to maintain
safety standards. In line with market norms it is recommended that the PPA be a so-called
“take or pay” contract under which the PPP partner would receive the tariff for all units of
power generated. In other words, the Municipality would not have the choice as to whether
to accept the power or not. There is very limited risk to the Municipality of such a structure
as the amount of power to be delivered is under 1% of total power demand by the Municipality
and therefore at all times the power will be required by the Municipality and can be on-sold
to Municipal customers. The Municipality will simply reduce its bulk purchases from Eskom
by the same amount.
Under circumstances where the Municipal grid physically cannot accept the power, for
example where there is a failure of a local powerline or transformer, the PPA will allow for
deemed energy payments at the same tariff. There is typically a threshold of allowable grid
downtime per year below which the deemed energy is not paid and the determination of this
period is a technical and financial issue to be considered and determined by the Municipality.
The above payment structure is recommended to provide sufficient certainty to allow for
private sector participation and financing, while limiting risk to the Municipality to acceptable
levels.
5.2 Institutional Capacity
The eThekwini municipality has the requisite capacity to procure, implement, manage,
enforce, monitor and report on the PPP. The project has been conceptualized and managed
from the eThekwini Water and Sanitation (“EWS”) department, as the manager of the
reservoir sites. However, the EWS department is collaborating with the Municipal Electricity
Department on a number of financial and technical aspects of the project and it is expected
that a joint approach will be required to ensure a successful PPP process.
The Municipality’s Electricity Department has experience with renewable energy
interconnections. The department was involved in the development of the landfill gas to
electricity projects at the two municipal landfill sites – Mariannhill and Bisasar – which were
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commissioned in 2006 and 2008 respectively. However these two projects are coming to an
end and therefore there is interest within the Municipality for the addition of new renewable
generation within its boundaries to support its policy objectives.
The Municipality also has experience of managing solar PV installation projects, having installed
solar PV panels on five Municipal buildings as a pilot project that aimed to promote the use
of embedded rooftop solar PV generation in eThekwini and reduce the dependence on the
national energy grid. The building installations were made at the uShaka Marine World Theme
Park (135 kW), Moses Mabhida Stadium Sky Car (112 kW), Kings Park swimming pool (110
kW), People’s Park restaurant, Metro Police Headquarters (115 kW), eThekwini Water and
Sanitation’s Customer Service Department (45 kW) and at Loram House, home to Durban’s
strategic projects unit (5 kW).
The rooftop PV project also aimed to provide opportunities for learning about PV
installations. The project provided practical experience for the department on various aspects
of solar PV technology such as electricity generation profiles at different times of the day and
year of the various technologies and sizes, quality control, monitoring and evaluation of
generation performance. The Municipality’s Energy Office was the overall project
management unit for these projects.
Several municipal electrical engineers have also attended specialised training courses on solar
PV installations. The envisaged PPP might also be an opportunity for staff to be involved in
larger scale projects and for technology and skills transfer to occur from the private partner
to the municipal staff. There are also a number of resources available to assist municipal
officials in solar PV procurement, including guidance provided by the CSIR and other
institutions.
Given that the envisaged project will be based on sites managed by the EWS, but that the
installations will interface with and export power to the Municipal electrical distribution
network it is likely that both departments will be required to contribute to the project design
and procurement process and will also have separate responsibilities for implementation and
contract and performance management. It is therefore recommended that a project team is
established from these departments as well as potentially officials from the Municipal finance
and supply chain management departments. The team should determine the allocation of
responsibilities for project oversight, performance monitoring and contract management and
preferably establish a simple document confirming this allocation.
A key technical component of the project feasibility assessment is confirmation of the ability
of the separate installations to feed into the local grid and an evaluation of the costs of this
connection – including any associated grid strengthening required. This evaluation is best
performed by the Electricity Department. At this stage this has not been completed and
remains a key item to be addressed.
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6 VALUE ASSESSMENT All municipal PPPs governed by the Municipal Public-Private Partnership Regulations are
subjected to three strict tests:
Can the municipality afford the deal?
Is it a value-for-money solution?
Is substantial technical, operational and financial risk transferred to the PPP partner?
These three tested are considered below.
6.1 Affordability
The first test is whether the municipality can afford the deal.
6.1.1 Internal assessment
As the output of the envisaged project will be a replacement of the purchase of bulk electricity
the main budgetary implication is a reduction in budgeted bulk electricity purchases but
balanced by the annual costs of the PPA. Estimates of these cost reductions have been
calculated at the expected maximum tariff level and in the Low Case would be a reduction of
R8.6m per year in bulk power purchases matched by a corresponding PPA payment obligation.
The above costs are annual operating costs that would escalate in line with Eskom wholesale
tariff escalation.
There are certain capital costs that would be incurred by the municipality in project
implementation. These are primarily the costs of grid connection, if borne by the Municipality,
and any associated costs to be borne by the Electricity Department. Initial costs estimates for
the grid connection are R9.4m for the Low Case project however some sites have not yet
been evaluated and these costs are still to be fully determined –it is noted that the Municipality
has indicated that the default approach is that grid connection costs are to be passed to the
PPP partner as far as possible. To ensure that the Municipality could review the financial
impact on the Project post implementation it would be important to separately record all the
transaction and ancillary costs of the Project in a consolidated budget.
The final site assessment by the EWS and specific contract conditions to be determined, such
as allocation of responsibilities for site security, may impose additional operational costs on
the EWS that will need to identified and included in their operational budget.
In general, the bulk of the project monitoring costs can be passed to the PPP partner via
contractual conditions requiring regular reporting from the PPP partner. The internal
municipal costs of monitoring and contract management are likely to be relatively low as a
PPA relies on a single, easily measurable unitary payment approach with very little interface
with municipal operations.
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6.1.2 Technical definition of project
The project has been defined as a portfolio of separate ground-mounted, fixed tilt solar PV
installations each of a minimum size of 100kWp and a maximum size of 1MWp AC to be built
on municipal reservoir sites by a PPP partner. Power from each installation will be supplied
to the local distribution grid through a double meter per project and governed by a PPA. The
responsibility for all grid connection and related infrastructure on the municipal side of the
meter will be borne by the municipality, however it is the intention of the Municipality that
the costs of the grid connection are to be borne by the PPP partner. The final design and
construction responsibility and costs for the installation will be borne by the PPP partner. All
operating and maintenance costs and power generation risks of the installations will be borne
by the PPP partner.
The site conditions suggest that the High Case would be installations on 39 sites with a total
installed capacity of 9.8MWp and that the smaller but more realistic Low Case would result
in installations on seven sites with a total installed capacity of 4.6MWp. The final size would
depend on private sector interest and pricing and would be affected by the final procurement
approaches and risk allocation decided on.
6.1.3 Direct and Indirect Costs
The cost estimates and assumptions have been detailed in section 3.3. A key determinant of
the direct costs are the current capital costs of solar PV equipment. The below estimates
were used for the technical assessment:
sites above 300kWp was R14 264/kWp and;
sites smaller than 300kWp the cost was R16 141/kWp.
However, it is noted that capital costs for solar PV are subject to rapid change and in general
have shown considerable declines in certain cost components over recent years. Panel prices
have reduced in particular, but there have also be declines in costs of other important items
such as inverters and mounting systems. Recent market intelligence suggests that total capital
costs have reduced to below R12 000/kWp which is a material decrease on the above costs
and for the purposes of the second financial modelling exercise the base case in the model
uses costs of R11 578/kWp as an average capital cost.
It is recommended therefore that an EOI process is conducted prior to a final decision on the
project implementation and design.
Operating costs were estimated at 3% of capital costs which is a relatively typical metric used
in industry analysis at the pre-feasibility level. These costs would be borne by the PPP partner.
NPV and Project Finance Model Assumptions
The assumptions used in the initial NPV assessment modelling and the second project finance
modelling exercise are outlined in section 3.3.
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Tariff estimation
For the purposes of the costs to be saved, in other words the reduction of bulk power
purchases, a weighted average tariff was determined based on an estimated time of generation
of the project weighted by the current Eskom Megaflex municipal tariff schedule. It is noted
that this is subject to change dependent on Eskom tariff restructuring and approval by NERSA
of Eskom’s tariff applications which happens on a three-year basis.
The weighted average tariff used for the NPV analysis was 83c/kWh. This was updated in the
financial model based on the most recent NERSA tariff determination which occurred after
the technical assessment and a value of 102c/kWh was derived and used as the starting tariff
in 2019/20.
Dependent on certain technical assumptions there may be small variations (in the order of
5% variation in either direction) in the actual weighted tariff.
Indirect costs
As noted, the municipality still needs to finalise the identification and quantification of indirect
costs, these including:
Procurement and project design costs
Grid connection costs
Monitoring and project management costs.
6.1.4 Power Purchase Agreement
In terms of current Municipal policy the maximum energy rates that the municipality is allowed
to pay for energy purchased from embedded generators is capped at the rates at which the
department buys power from the national utility, Eskom. These rates are based on the
Megaflex tariff structure applicable to municipalities with the applicable rates schedule being
those at 275kV and at 300-to-600 km distribution distance.
While this rates structure provides limited incentives to support renewable energy projects,
at this stage the Municipality has noted that they cannot negotiate higher rates. Payment is
based on the avoided cost principle – instead of paying Eskom, the Municipality pays the local
generator.
As the Megaflex tariff structure is a time-of-use structure, energy rates are paid to generators
based on when they generate the electricity. Peak time periods attract the highest rates whilst
off-peak attract the lowest. A voltage surcharge is payable to embedded generators to
consider savings of distribution losses compared to bulk purchases from outside the
distribution network.
The eThekwini Electricity Department is obliged to operate within the bounds of the MFMA
and to buy power from local electricity generators the department will have to enter into a
PPA that is in accordance with the MFMA and also meet the value for money test of the PPP
regulations.
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If the PPA is structured with the following conditions on the unitary payment then there will
be no additional cost of power to the Municipality:
Time of use tariff which matches the wholesale time of use tariff faced by the
Municipality;
Maximum tariff to be equal to or less than the wholesale time of use tariff faced by the
Municipality plus the municipal avoided losses surcharge.
It is cautioned that the above restrictions may make it difficult for the private sector to make
a credible offer and hence an EOI is recommended prior to issuing an RFP.
Of course, if a procurement process results in tariffs being offered below the wholesale price
of power there will be net savings to the Municipality. These can only be determined once
the procurement process is undertaken or at least evaluated with a reasonable degree of
accuracy once a market sounding exercise is undertaken.
In addition to the tariff restrictions and tariff level that will be determined through a
competitive procurement process, the PPA will include the following key elements:
Duration of contract
Technical obligations
Financial Terms and Conditions
Local content obligations
Broad based black economic empowerment obligations
Metering aspects
Reporting obligations
General Contractual Issues.
6.2 Value for Money
A simplified value assessment was conducted as per the PPP Guidelines. The Municipality has
stated that at this stage no budget allocation will be made available for the capital costs of the
project and hence have ruled out the delivery of the project by the Municipality on budgetary
grounds. There are also sound risk reasons why the construction and especially long term
operations of the project are not appropriate for the Municipality to undertake.
A public sector comparator has not been used for this reason and also since the project is
not a replacement of a service provided by the Municipality but rather the replacement of a
bulk purchase. Value for money can therefore be determined by a comparison between the
costs of the purchase under a continuation of current practices versus the costs of the
purchase from the project (net of any additional transaction costs).
This is in line with the PPP Guidelines which explain that a simplified value-for-money
assessment should be carried out when the undertaking of the output to be assessed is not a
realistic public-sector option. It may not be an option for a variety of reasons including a lack
of funding, technical capacity or previous experience in providing the output.
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A simple external reference model was used to ensure that the project was affordable and to
establish a benchmark against which to evaluate the bids. This was premised on the unitary
tariff payment outlined above and resulted in the determination of the Low Case for the
project which is comprised of those sites that could deliver a positive NPV to a private
provider at the upper bound tariff level.
The key value-for-money drivers outlined in the PPP Guidelines are tabled below with an
indication of how they can be met within an envisaged project design and procurement
process:
Table 19. Value for money drivers
Value for Money Driver How Addressed
Project objectives expressed as
measurable outputs
Yes. Unitary payments under the PPA to be in
kWh of power delivered at the project meter.
Incentive for demonstrable innovation
by the PPP partner
Yes. Final design to be provided by the PPP
partner within the bounds of technical, social and
environmental constraints. Technology choice
and design innovation incentivised by price
competitiveness.
Transfer of substantial financial,
technical and operational risks to the
PPP partner
Yes. Construction and operation risk to be
wholly transferred to the PPP partner.
Competitive procurement as to which
there are a sufficient number of
qualified private sector firms that may
bid
Yes. Can be based on many public and private
sector procurement processes for direct off-take
solar PV projects. Clear evidence of a
competitive and competent local private sector.
Contract design reflecting good PPP
contracting practices to provide for
efficient monitoring and regulation.
Yes. As above, there are numerous examples of
similar contracting processes and efficient
monitoring and regulation to be addressed in
final procurement and project contracts.
Increased direct revenue to the
municipality
No increase in revenue. Depending on final tariffs
bid by private parties there may be a reduction in
direct municipal costs of bulk power or a net
zero change in costs.
Increased socioeconomic activities
within the community
Yes. The project will lead to additional
employment during construction and to a lesser
extent during operations as well as multiplier
effects of this employment and expenditure.
Optimal use of under-performing
assets
Yes. The project would use existing idle land on
reservoir sites of the municipality.
Job creation As above.
BEE The procurement would include BEE
requirements as per Municipal supply chain
policy.
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Value for Money Driver How Addressed
Further socio-economic requirements can be
included in the procurement process as long as
project viability is maintained.
A simplified NVP calculation of the project as a whole is presented below.
Table 20. Indicative NPV of project Low Case compared to current practice
Net Present Value of Project Against Baseline (all costs in Rm)
NPV Net Cost/Benefit
Municipal Costs / Benefits
Avoided Cost of Electricity Purchases (Baseline) 95.24
Grid Connection Costs =
- 0.00
Transaction Costs = -1.00 -1.00
M&E Costs = X% of Contract Payments/yr 1.00% -0.95
Retained Municipal Risk -2.23
Total Municipal Costs / Benefits 91.06
Project (PPA) Costs
Discount Rate = 9.10%
Period (years) = 20.00
NPV of Contract Payments
At Megaflex (plus Surcharge) -95.24 -4.18
2.5% below Megaflex -2.50% -92.86 -1.80
5.0% below Megaflex -5.00% -90.48 0.58
7.5% below Megaflex -7.50% -88.10 2.96
The analysis shows that the Municipality requires a Tariff that is approximately 5% less than
Eskom Megaflex to recover its transaction costs and to cover the NPV of retained project
risks and to have a positive NPV - beyond that level there are net financial benefits to the
Municipality.
The remaining risks would largely fall to the PPP partner and would be specifically allocated
within the PPA. Therefore, it can be concluded that substantial technical, operational and
financial risk would be transferred to the PPP partner.
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6.2.1 Additional economic or financial values
The above analysis does not include the economic value of other value for money
considerations, these being:
Economic multiplier of local content
Increased national and local employment
GHG emission reductions
The potential for future green power sales at a premium
The potential for future green power sales in the future is an important item to consider as
this reflects potential realisable revenue from the project, rather than only economic value.
The value of renewable energy generation could be captured through the sale of specific green
power credits to off-takers willing to pay a premium for renewable energy. In addition, there
may be the potential for such sales to be used as carbon tax offsets in the future.
These values are all relatively difficult to quantify for a small project of this nature but can be
added to the analysis in due course if required by the Municipality pursuant to final decisions
on the project.
6.2.2 Socio-Economic Benefits
There are other socio-economic benefit of the PPP that have not yet been quantified but
would be likely to arise.
A direct impact would be employment, as noted above, as it is expected that both the
construction phase and the operations and maintenance phase will create employment
opportunities. Apart from simple job creation, the introduction of relatively new technology
will create opportunities for acquisition of new skills in the field of renewable energy by local
technicians.
Similarly, the municipality can include knowledge transfer requirements in the project design
including structured programmes such as in-service training and internship. Through these
programmes, young graduates could undergo experiential trainings which will equip them with
knowledge required for career development.
The project would also be subject to the BEE requirements of the municipality and would
thereby also help advance previously disadvantaged citizens at both the ownership level and
operational level dependent on the targets set.
6.2.3 Municipal Strategy
As outlined above, in addition to the socio-economic benefits, the project will advance the
policies and strategies of the Municipality related to energy policy and climate change
mitigation and adaptation.
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6.3 Risk Assessment and Risk Transfer
A risk assessment is tabled below.
Table 21. Risk assessment and transfer
Category Description Mitigation Allocation
Availability The possibility that the
services do not meet
the output
specifications.
Very low impact risk
as municipality retains
Eskom backup.
Inherent penalty in the PPA
as PPP partner only paid on
delivery of power.
PPP partner
Completion
risks
Delay in completion of
works.
Very low impact risk
as municipality retains
Eskom backup and
therefore no costs of
delay.
PPP partner to bear EPC
risk under PPA.
PPP partner
Cost over-
run risks
Project costs exceed
budget
PPP partner to bear EPC
risk under PPA.
PPP partner
Design risk Project not meeting
output specifications.
Design specifications
leading to contractual
disputes with PPP
partner
PPA to require power
output to meet grid code
and safety specifications.
Design risk to be specified
as the PPP partner risk
under the contractual
agreements and allowance
to be made in procurement
process for site evaluation
and design review by the
PPP partner partner.
PPP partner
Municipality if
design risk not
suitably passed to
the PPP partner
Environmental
Risk
Possibility for liability
of environmental
damage
From construction or
operations or from
pre-transfer activities
1. Environmental
evaluation and
management plan to be
prepared by
municipality prior to
procurement
2. Allowance for bidder
due diligence of the site.
3. Contract specifications
to include
environmental
1. Municipality
2. PPP partner
3. PPP partner
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Category Description Mitigation Allocation
requirements to be met
by PPP partner.
Cultural and
Environmental
Failure to undertake
Heritage Impact
Assessment
The heritage resources
authority, Amafa aKwaZulu-
Natali Heritage Council and
the eThekwini Metro
Heritage forum are notified
of the proposed
development together with
a comprehensive report of
each of the potential sites.
1. Municipality
or
2. PPP partner
Land Use
Planning
Failure to obtain Land
Use Authorisations
Site appropriate land
development applications
must be submitted to the
relevant authority.
1. Municipality
or
2. PPP partner
Land Use
Planning
Lack of Municipal
building plan approval
Building plans must be
submitted and approved in
accordance with the
NBR&BSA
1. PPP partner
Land Use
Planning
Failure to obtain
Municipal Permits
Wherever Municipal
Permits are required, the
bylaws must be reviewed
and applications made in
terms thereof.
1. PPP partner
Environmental Failure to obtain
Biodiversity Consents
Employ services of
Environmental Assessment
Practitioner and undertake
an assessment of each
potential site upon which a
generation facility is planned
to be constructed in order
to ascertain whether there
is a potential risk to
biodiversity.
1. Municipality
or
2. PPP partner
Exchange rate
risks
Exchange rates
affecting project costs
PPP partner to bid tariff in
rands and to accept
exchange rate risk or
hedging costs.
PPP partner
Force
Majeure risk
Occurrence of events
beyond the control of
either party.
Limited impact for the
project as delays or
Define “Force Majeure”
narrowly to exclude risks
that can be insured against
and that can be better dealt
with by other measures.
PPP partner
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Category Description Mitigation Allocation
cost over-runs do not
affect PPA.
PPA to not allow tariff
variation or deemed energy
due to Force Majeure.
Inflation rate
risks
Possibility that actual
inflation will exceed
projected inflation.
This is only a risk if
the tariff is inflation
linked and that
inflation exceeds
Eskom tariff inflation.
Structure PPA so that
inflation is limited to CPI or
Eskom Megaflex inflation
whichever is the lower.
PPP partner
Note that this
places
considerable risk
on the PPP
partner and may
make the project
unviable
Insolvency
risk
Risk of insolvency of
the PPP partner. The
impact of the risk is
low as the Municipality
retains Eskom backup.
There may be risks of
costs of
decommissioning that
fall to the Municipality.
Contracts to allow
substitution of the PPP
partner or change in
control.
Contract to allow for step-
in rights by the Municipality
in the event of insolvency.
PPP partner
Insurance
risks
Risks that events of
concern are not
insurable or become
uninsurable.
1. PPP partner
contractually required
to hold insurances
typical of a small-scale
power utility.
2. Deemed energy
provisions to have
reasonable thresholds
for uninsured grid
events.
1. PPP partner
2. Municipality
Interest rate
risk
Risks of costs of
financing.
PPP partner to make
hedging or contingency
provisions.
PPP partner
Latent defect
risk
Risks of latent defects
in construction.
PPP partner to make
suitable provision in
construction contracts.
PPP partner
Maintenance
risk
Risks of deficiencies in
operations and
maintenance
PPP partner to make
suitable provision in
construction contracts or
to ensure adequate
maintenance budgets and
staffing.
PPP partner
Site risks Risks that the sites
would not be
The EWS department to
ensure that sites selected
Municipality
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Category Description Mitigation Allocation
correctly maintained
or secured to allow
the uninterrupted
operations of the
project
can be effectively
maintained and secured for
the lifespan of the project
and that costs of any
additional site maintenance
to be included in EWS
operational budgets.
Contracts to clearly specify
the level of site
maintenance to be provided
by the municipality.
Market
demand risk
Risk that demand for
the product is less
than expected.
The project would be
less than 1% of total
municipal power
demand and this risk is
therefore remote
Project scale limited to less
than 1% of current
municipal power demand
Municipality
Planning risk Risk that the planned
project will fail to
comply with applicable
laws.
1. EWS to review all
planning consents or
other land-use
requirements and to
confirm same with the
relevant municipal
departments.
2. Project contracts to
clearly specify any
planning or other
permits to be secured
by the PPP partner
1. Municipality
2. PPP partner
Political risks Risks of unforeseeable
conduct by organs of
state, including
expropriation and
nationalization or
discriminatory
conduct affecting PPP
partner returns.
Provide appropriate and
reasonable relief for the
PPP partner and any debt
providers for political risk
events
Municipality
Regulatory
Risks
Possibility that
required consents
from other organs of
government cannot be
obtained or are
1. Municipality to conduct
legal scan and to
request confirmation
from relevant organs of
government that no
additional regulatory
1. Municipality
2. PPP partner
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Category Description Mitigation Allocation
obtained at higher cost
than provided for.
requirements are
needed. Municipality to
secure any consents
required where possible
before procurement
and to provide for
transfer to the PPP
partner as required.
2. PPP partner to
undertake due diligence
on any regulatory
requirements under its
control (such as
occupational health and
safety)
Residual costs
risks
Risk that the costs of
decommissioning or
site clean-up.
Contract conditions to
include decommissioning or
hand-over obligations.
PPP partner
Resource
risks
Risks that estimated
solar resource is
lower than expected.
PPP partner to due
diligence resource forecasts
and to determine forecast
revenue based on
reasonable probabilities of
exceeding or falling below
forecast resource in any
particular year.
PPP partner
Tax rate
change risk
The risk that a change
in a tax rate may
materially affect the
returns to the PPP
partner
If change relates to
discriminatory conduct then
allow for compensation in
the PPA.
1. Municipality if
discriminatory
2. PPP partner if
general
change
Utilities risk Risk that the required
utilities, primarily the
grid, are not available
to support the project.
Risks that the grid
connection costs are
higher than anticipated
or are delayed.
1. Grid study by the
Electricity Department
and confirmation of
suitability of all sites for
connection as well as
grid ability to evacuate
power.
2. Deemed energy
provisions to protect
the PPP partner but to
include reasonable grid
unavailability.
1. Municipality
2. PPP partner
below
deemed
energy
thresholds
and
Municipality
above the
thresholds.
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The risk analysis suggests that the risks of the project are very much in line with typical risks
of ring-fenced project finance transactions. As such the majority of these risks, such as
construction over-runs, operational costs and generation performance can be contractually
passed to the PPP partner. In this regard the majority of the technical, operational and financial
risk could be transferred to the PPP partner under suitable contracting arrangements.
As it has been identified that certain environmental risks may arise during the life cycle of the
project, it is advised that the Municipality undertake a thorough assessment of any potential
environmental risks, including whether they may require an EIA, as well as develop an
appropriate environmental management plan for the entirety of the project in relation to each
of the individual sites. This can be achieved by the Municipality through co-operative
governance consultations with the KwaZulu-Natal Department of Economic Development,
Tourism and Environmental Affairs where required.
Some risks that would be retained by the municipality can be regarded as non-material. These
include the availability and completion risks of the project which pose little risk to the
municipality’s power supply since the project would provide such a small percentage of power
purchases and any shortfall would simply reflect in higher bulk purchases from Eskom.
The municipality’s major material retained risks are:
Design risk: although the procurement process would be structured to pass this risk
to the PPP partner, the municipality would retain some risk if this process was not
done correctly. For example, if any misrepresentations or incorrect information were
provided to the PPP partner that affected their project design and performance.
Environmental risk: this risk does not appear to be significant but it is likely that
the municipality would need to undertake an initial scoping of any environmental risks
and to provide an appropriate environmental plan for the project to be met by the
PPP partner and contractually enforced.
Planning risks: this risk can be mitigated by the municipality undertaking thorough
internal consultation and due diligence to ensure that all planning and related consents
are in place or could reasonably be obtained for the project.
Site risks: the sites for the project are to be provided and maintained and secured
by the municipality and the risks of the ongoing maintenance of the sites will remain
with the municipality for the period of the project and will need to be addressed with
within the EWS operating plans and budget.
Regulatory risks: as above this risk can be mitigated by thorough consultation with
the key regulatory institutions, these being NERSA, National and Provincial Treasury,
and the DoE.
Utilities (grid connection and grid stability) risks: the connection to the local
grid is the key interface, aside from the provision of the land itself, for the project.
There are a number of risks related to this. The first is that if the grid connection costs
and responsibilities fall to the Municipality there remain risks of cost over-runs and
technical problems in building the connection points and evacuating the power. There
are also would be ongoing deemed energy payment risks if the grid was not available
to accept the power produced by the projects above the deemed energy thresholds.
This risk can be mitigated by participation of the Electricity Department in the
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transaction team and confirmation from the department that the necessary grid
studies and design and cost estimates have been undertaken and that the required
budget, approvals and human resources are in place to undertake the required works.
The remaining risks, as per the table above, would largely fall to the PPP partner and would
be specifically allocated within the PPA, as further outlined in the section below.
6.3.1 Project and contracting structure
The project structure would be governed by a bilateral agreement (or agreements) between
the PPP partner and the eThekwini Municipality. The agreement/s would be structured so
that the PPP partner would:
Take the financial, technical and operational risks of designing, building and operating
the project, including the resource risk of solar irradiation forecasts;
Receive a unitary payment for power delivered to the local distribution grid, with a
suitable tariff determination based on a time-of-supply tariff that escalated at an agreed
rate. The PPA would be a self-despatch or take-or-pay structure under which the
municipality would have to accept and pay for all power generated by the project;
Have rights to the use of allocated land maintained and secured by the EWS for the
period of the PPA for power generation purposes.
It is recommended that independent legal advice is procured for the drafting of the PPA and
any associated legal agreements recommended by external legal counsel. For example, legal
counsel will determine whether a separate land availability, rental or lease agreement over
the land is required or whether this can be contained within the PPA itself.
If there is a likelihood that the PPP partner would raise project finance in the form of long
term debt for the project there might also be the need for the municipality to enter into so-
called direct agreements with the lenders to the project to give them their required rights to
step into the position of the PPP partner.
It is recommended that as part of the EOI the key terms of the PPA and the direct agreements
are outlined and discussed with market participants and potential bidders to ensure that these
documents do not pose barriers to private sector participation in the project.
6.4 Summary
In summary:
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Consideration Summary Position
NPV estimate Preliminary estimates suggest that the net change in NPV
over the baseline (business as usual) would range from -R4.2m
to +R3.0m at 0% to 7.5% discount to the Megaflex tariff.
It is stressed that these are high level and preliminary
estimates at this stage and are based on presumed tariff levels
that are indeterminate until procurement has taken place.
As noted below the estimates have been conducted on the
Low Case.
Power capacity and
generation
The project looks technically feasible at a High Case of
9.8MW across 39 sites and a Low Case of 4.6MW across
seven sites. The Low Case appears to be the more likely
scenario based on the NPV that the PPP partner would
achieve at the site level. The seven sites are: Woodlands Tank
3 & 4, Montille 1 & 2, Dunkeld, Umlazi 2, Phoenix 2,
Chatsworth 4 and Northdene.
The respective annual generation would be 7 118MWh and 14
601MWh per year. This is equivalent to approximately 0.07%
and 0.13% of the total power purchased by the municipality.
GHG reduction The project would reduce between 8 500 tCO2e and 19
000tCO2e per year at the Low and High Cases respectively
Statement of affordability The municipality would incur minimal net annual costs under
the proposed project structure where the project tariff would
be restricted to be less than or equal to the cost of bulk
power purchases by the municipality.
The municipality would need to confirm that the transaction
and associated grid connection costs where affordable to the
municipality.
Statement of value for
money, if appropriate
On the indicative assumptions the project provides value for
money in the sense that:
- The project assists the municipality in meeting its
strategic objectives as expressed in its energy and
environmental strategy
- The majority of risk is transferred to the PPP partner
- There are additional socio-economic benefits to the
municipal area
The project would provide financial benefits to the
municipality in the event that project tariffs were lower than
the equivalent energy costs of bulk power purchases by the
municipality. However these tariffs will only be known
following a procurement process.
Recommended
procurement choice
It is recommended that the procurement is carried out via an
EOI followed by an RFP :
- A competitive tender based on
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Consideration Summary Position
o Threshold test of whether bidder meets the
technical, financial and socio-economic
qualification criteria; and
o The bid tariff and escalation factor
o RFQ/EOI and RFP stages are recommended.
Information verification This report has identified information still required for final
feasibility assessment and prior to procurement. This includes:
- Final grid connection costs and feasibility per site
- Detailed site condition assessment
- Detailed evaluation of any required planning consents
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7 PROCUREMENT PLAN A simple procurement plan is outlined below, pending further discussions with the EWS. A
final procurement plan will need to be developed in accordance with the MFMA and with the
municipal supply-chain management policies.
Circular 62 of the MFMA states that infrastructure projects above the value of R10 million
(all applicable taxes included) may only be advertised after the CFO has verified in writing that
budgetary provision exists for the commencement of the particular project. A letter from the
CFO confirming enough budget to fund the programme shall be required prior to the
commencement of the procurement process.
7.1 Market Interest
Although the evaluation has provided an indication that the project can achieve a positive
NPV for a private provider there are a range of other factors that affect the market interest
deliverin ing the project. It appears reasonably certain that market capability exists,
a two stage RFP process is conducted. It is therefore proposed that as per the Guidelines,
with an EOI followed by an RFP
Private sector bidders are likely to look closely at the Internal Rate of Return (“IRR”) on
equity or possibly pay-back periods. IRR in turn will be determined to a significant degree by
such factors as: allocation of costs between the Municipality and the PPP partner, risk
allocation within the PPA, specific site conditions, CPG requirements and so forth.
Is there the capability within the private sector to deliver the required services given
the site characteristics?
Is it possible that such delivery would provide value for money and is it likely that the
market could provide the service at or below the tariff constraints?
What are the BEE enterprises in the sectors and are BEE charters being implemented
and how could the BEE, CPG and other socio-economic objectives best be included
in the procurement process?
What levels of market competition are there likely to be?
Is it likely that the private sector could secure the required finance for the project and
what would be the terms and conditions for such finance?
Key PPA terms and conditions and other risk transfer issues that would affect the
ability and appetite of the private sector bid and to offer tariffs below the target level.
It is recommended that an EOI is issued prior to an RFP - in other words the private sector
is invited to express interest in the project – to seek views from these market participants on
project feasibility, project and contract structure and procurement approach and to identify
the availability of suitable bidders.
Given the extensive experience of the private sector in the national Renewable Energy
Independent Power Producers Programme (“REIPPP”) and other renewable energy
procurement processes conducted by private offtakes there is a relatively well-informed and
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prepared private sector in this market and it is expected that a quick and efficient EOI process
could be established which would enhance the chances of success of a procurement process.
It is recommended that in line with similar experience in the REIPPP a non-negotiable set of
project agreements are prepared prior to procurement and based on feedback received in
the EOI. This would allow for a bid evaluation to be conducted on a comparable set of bids
and would also minimise negotiation at the preferred bidder stage and improve the chances
of successful project contracting and implementation.
The downside of the above approach is that the municipality would need to incur legal costs
at risks prior to RFP stage.
7.2 PPP Procurement
It is recommended that the final procurement approach would be informed by the EOI
response. A single stage procurement process could also be followed with a single Request
for Proposals (“RFP”) issued to the market, however based on the feasibility study review
there are risks that such an approach may not lead to a successful procurement process.
The RFP would need to follow the PPP approach of:
TVRIIA review by Treasury of the draft RFP and associated contracts including the
PPA
RFP issuance
Evaluation of bidder responses
TVRIIB value for money report and preferred bidder selection
This would be followed by final bidder negotiations and conclusion of contractual agreements,
following which:
TVRIII Treasury approval
Solicitation of public participation and other actions required for s.33 of the MFMA
approval
Council resolution supporting s.33 and the PPP contracts
Sign agreements
The above process is subject to municipal confirmation. With due consideration to internal
capacity and budget the municipality should also establish a reasonable timeframe for the
process.
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Potential risks relating to the implementation of the PPP procurement process:
Table 22: PPP Procurement Potential Risks and Mitigation Plan
Risk
No
Description of
Risk
Impact Probability Mitigation Plan
Cost Time Quality
1 Delays in the
commencement of
the procurement
process due to
dependencies on
environmental
authorisations and
other licensing/
permitting
requirements.
H H L M These activities to be executed
in the lead up to the
procurement process.
EWS will make the Project
Steering Committee aware of
the licensing and permitting
requirements. The activities will
be tracked continuously to
ensure delays are swiftly
unblocked and delays
prevented.
2 Timelines overrun
due to National
Treasury’s TVR
process lead times,
especially given the
fact that both the
national and
provincial
government are
aware of these.
L H L H Project team to communicate
the procurement plan with the
relevant treasury
representatives and agree
turnaround times or the
submission of TVR responses.
Project team to also notify the
treasury representatives ahead
of submitting items for their
review, to ensure they are
prepared to set aside time to
review and provide input on the
TVR requests.
VL: Very Low; L: Low; M: Medium; H: High; VH: Very High
7.3 Municipal PPP Process Compliance
The Municipality will undertake the necessary public consultation processes in terms of the
PPP Guidelines. To that effect this report does not include several specific public consultation
and compliance steps that will need to be undertaken prior to implementation of the Project.
7.3.1 Statement of Compliance with Comments and Representations
This report does not include municipal statements of compliance with the comments and
representations received in response to MFMA section 120(6)(b) invitation to comment, as
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appropriate. These processes will be undertaken by the Municipality once a decision to
proceed to the next stage has been taken.
7.3.2 Statement of Views and Recommendations Received
This report does not include:
Statement of views and recommendations received in response to any required MFMA
section 120(6)(c) solicitation
General public notification with written comments requested within 30 days of
notification. Section 120(6)(b)(i and ii) of the MFMA. Format in accordance with
section 21(1) to (5) of the MSA if public participation for municipal support
activities/private sector use of municipal property is required.
These processes will be undertaken by the Municipality once a decision to proceed to the
next stage has been taken.
8 RECOMMENDATIONS
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This report is structured to evaluate the feasibility of the proposed project and has provided
this evaluation as per the PPP Guidelines. In the course of the feasibility evaluation a number
of recommendations towards the execution of the project have been made. Key
recommendations in this regard are summarised below:
Technical and grid connection:
A key technical component of the project feasibility assessment is confirmation of the
ability of the separate installations to feed into the local grid and an evaluation of the
costs of this connection – including any associated grid strengthening required. This
evaluation is best performed by the Electricity Department. At this stage this has not
been completed and remains a key item to be addressed.
Following completion of full assessment of the grid connection costs the Municipality
should determine whether to spread the grid connection costs across the portfolio
or whether to consider each site separately in the RFP. If each site were to be
considered separately some sites, those where the grid costs are a smaller percentage
of total capital costs, would have greater financial viability than others and hence
potentially a different tariff to others. If site were bid separately this could allow for
the Municipality to select those with the lowest tariffs.
Procurement and Institutional Management:
The project has been conceptualised and managed from EWS, as the manager of the
reservoir sites. However, EWS is collaborating with the eThekwini Electricity
Department on the financial and technical aspects of the project and it is expected
that a joint approach will be required to ensure a successful PPP process. It is therefore
recommended that a project team is established from these departments as well as
potentially officials from the municipal finance and supply chain management
departments. The team should determine the allocation of responsibilities for project
oversight, performance monitoring and contract management and preferably establish
a simple document confirming this allocation.
Given that the envisaged project will be based on sites managed by the EWS, but that
the installations will interface with and export power to the Municipal electrical
distribution network it is likely that both departments will be required to contribute
to the project design and procurement process and will also have separate
responsibilities for implementation and contract and performance management. It is
therefore recommended that a project team is established from these departments as
well as potentially officials from the Municipal finance and supply chain management
departments. The team should determine the allocation of responsibilities for project
oversight, performance monitoring and contract management and preferably establish
a simple document confirming this allocation.
Although the evaluation has provided an indication that the project can achieve a
positive NPV there is less certainty on market appetite since the projected private
sector returns are sensitive to certain assumptions and contract terms and may not
be attractive to private investment at the lower end of the range. It is therefore
recommended that the Municipality should include an Expression of Interest (“EOI”)
stage in the procurement process before proceeding to a full Request for Proposals
(“RFP”).
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o It is also suggested that the EOI is also used to test key PPA terms and
conditions and other risk transfer issues that would affect the ability and
appetite of the private sector to bid and to offer tariffs below the target level.
Given the relatively low returns on the base case it is recommended that the
Municipality consider the application of available grants or other capital subsidies that
may be available through the national municipal grants system or from other sources.
Although each site will have a separate installation of less than 1MW and a separate
connection point, there is the potential that NERSA could deem the entire portfolio
a single project if there is a single use-of-system agreement with the Municipality or a
single PPA. It is therefore recommended that NERSA is approached to understand
their view on this issue. If there is remaining uncertainty there may be the requirement
for further legal advice on whether NERSA can legally adopt such a stance and if so,
whether this could be addressed through an appropriate project structure such that
each site is legally separate and is contracted via a separate PPA and connection and
use-of system agreement.
As each site has a different grid connection cost each site will have a different capital
cost and hence a different return. It is important to note that final portfolio
determination and hence the final total size of the project can only be made following
further technical, financial and risk assessment and therefore it is recommended that
the following actions are undertaken prior to issuance of the RFP:
o Completion of the assessment and costing of local grid connections for all the
sites under consideration;
o Final site filtering based on determined characteristics such as ground
conditions, security, shading and accessibility;
It is recommended that as the private sector bid tariffs cannot be known until the
procurement process, it may also be appropriate to design a procurement process
that allows for some flexibility in the final total project size and number of sites
included.
Environmental:
It is recommended that either internal environmental management staff or a suitably
qualified external consultant undertake a rapid risk assessment and prepare a simple
environmental management plan that the PPP partner would need to implement and
abide by. This plan would be included as part of the technical requirements under the
procurement process.
The measurement processes of the site conditions and the assumptions underpinning
the technical performance and costs of the project have been outlined in the relevant
sections of the report. These measurements are appropriate to this stage in the
feasibility study process. It is noted, however, that there may be site specific ground
conditions that affect final project costs and further evaluation of these, or the passing
of ground risk to the PPP partner, is recommended.
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Power Purchase Agreement:
In line with market norms it is recommended that the PPA be a so-called “take or
pay” contract under which the PPP partner would receive the tariff for all units of
power generated. In other words, the Municipality would not have the choice as to
whether to accept the power or not.
It is recommended that independent legal advice is procured for the drafting of the
PPA and any associated legal agreements recommended by external legal counsel. For
example, legal counsel will determine whether a separate land availability, rental or
lease agreement over the land is required or whether this can be contained within the
PPA itself.
It is recommended that in line with similar experience in the REIPPP a non-negotiable
set of project agreements are prepared prior to procurement and based on feedback
received in the EOI. This would allow for a bid evaluation to be conducted on a
comparable set of bids and would also minimise negotiation at the preferred bidder
stage and improve the chances of successful project contracting and implementation.
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9 APPENDICES APPENDIX 1: Land Due Diligence Report
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