The group of authors who donated their expertise (and time!) to this
book came together for a simple and collective intent: to address the
critical deficit of transmission capacity in Sub-Saharan Africa. It is
stated that roughly half the population of Sub-Saharan Africa (or 600
million people) lack reliable access to electricity. The lack of
electricity access is particularly stark at a time when the global
number of persons without access to electricity is falling.
While there is no adequate information on the breakdown between
generation, transmission, and distribution, historically investment in
generation has been roughly four times higher than transmission and
distribution combined. Furthermore, the distribution sector has also
attracted more investment than transmission, leaving this segment of the African energy market as the most impacted by a lack of
both public and private investment.
The critical nature of transmission infrastructure to the overall
function of an energy market cannot be overstated. As generation expands, transmission is needed to bring electricity to
the demand centres. Additional transmission capacity (including
cross-border) can also provide access to large power generation sources
and connect them to unserved demand. Transmission across national
borders, often referred to as interconnection, enables economies of
scale that bring down the cost of power and allow for greater efficiency
in matching production with consumption.
Current estimates place the total investment requirements for the
period 2014-2040 at $80-$140 billion, which equates to $3.2–$5.4 billion per year.
Of the 38 Sub-Saharan African countries, 9 have no
transmission lines above 100 kilovolts (kV). The scale of the
transmission deficit is also significant when one considers that the
combined length of transmission in the 38 Sub-Saharan African countries is about
112,196 km, less than the length of the domestic transmission network of
Brazil. The following Figure 1.1 helps further illustrate the transmission
deficit in Sub-Saharan Africa as compared to energy markets around the
world.
Figure 1.1: Transmission lines per capita (Source: World Bank, 2017: Linking Up: Public-Private Partnerships in Power Transmission in
Africa)
At a time when the world is coming together to address the threat of
climate change, it is also important to note that transmission
infrastructure is essential to the transition towards a less
carbon-intensive power market. Without it, many grid-connected
utility-scale renewable energy projects cannot be implemented. More importantly, developing and maintaining highly optimised transmission systems that can manage the
intermittent nature of renewable energy helps to reduce technical losses
and avoid the need to build additional generation or storage
capacity.
The critical lack of development of transmission infrastructure in
Sub-Saharan Africa, despite the increased investment in other segments
of the power value chain, naturally leads to two important questions: How did
the situation become so dire? and how can we overcome the transmission
deficit to widen the access to energy? The first question demands an
intense inquiry into economics, politics, sociology and geography that
is beyond the capacity of the authors of this handbook. The second
question, however, can be answered constructively and is the focus of
this book.
The Need for Private Sector Investment
Virtually all development of transmission infrastructure in Sub-Saharan
Africa remains within the responsibility of fully or partially
state-owned utilities. One reason is that it is difficult to prioritise and justify
transmission projects when transmission costs are not clear and transparently allocated
within the sector. As a result, the utilities that currently manage
transmission infrastructure often require public subsidies to counter
operating losses that arise when costs are not properly allocated and recouped. These subsidies usually take the form of direct budget support from
the government. The effect is that state-owned utilities are not incentivised or able to invest in new projects.
This vicious circle of generating losses and failing to invest in new
infrastructure is not inevitable. There are numerous examples around the
world where energy markets have been able to overcome this transmission
deficit through a combination of concerted regulatory reform and
partnership with the private sector. This book presents these examples
as case studies distributed throughout the chapters. The common
narrative across the experiences from other markets is as follows: if
the existing market actors (government, utility, regulator) can bring
clarity and predictability to the transmission sector, the private
sector can deploy its expertise and capital to overcome the
infrastructure gap.
It is important to note at the outset of this book that the primary
constraint on private investment is not the lack of the availability of
capital (see chapter 2. Financing Structures and Capital Sources). The key constraint is, rather, the ability to access that funding
through market regulations and project structures that provide the
predictable operating conditions and revenue that are fundamental to any
commercial investment. This book is intended to outline how public
officials can satisfy these expectations from the private sector through
a general description of transmission sector regulation, planning and
operation, and a detailed explanation of the structures for private
investment in the transmission sector.
Private partners, not funders
As previously noted, the existing transmission gap in Sub-Saharan
Africa is driven in large part by the inability to fund new
infrastructure through public budgets or finance public infrastructure
due to a history of operating losses. Thus, the first motivating factor for using private capital to fund
transmission infrastructure is to mobilise finance over and above what
the public sector may be able to provide. The private sector is not, however, simply a source of capital. It is
also a partner in project management, cost control and risk mitigation.
With the appropriate set of incentives, the private sector can be an
extremely efficient implementation model for transmission projects at a
low cost and on schedule. Successful private transmission projects have
been implemented in India, Latin America, the Philippines, United
Kingdom, and elsewhere. Brazil alone has financed over 50,000 km of
transmission lines through private investments.
Inviting private investment in the transmission sector can also bring
innovation through the utilisation of state-of-the-art technologies
which are transforming the energy landscape. For example, smart grid technologie
introduce new capabilities and provide opportunities for more
efficiency, as well as new services (energy management, distributed
generation, internet and telecoms).
Increasing role of the private sector in transmission
While private investment is not as widespread in transmission as in power generation,
there is substantial experience worldwide. In addition to
well-functioning power markets in OECD countries (e.g., United Kingdom),
private transmission has become common in the last twenty years across
Latin America and in countries such as India, Kazakhstan, and the
Philippines. Just in the period 2000-2015, multiple projects
materialised in Latin America as summarised in Figure 1.2.
Figure 1.2: Examples of private participation in transmission
infrastructure between 2000-2015
Similarly, India has developed more than 500 km of 400kV and 765kV
lines through private investment. Kazakhstan has a privately owned and
financed transmission system, and the Philippines privatised their
existing transmission system through a 25-year concession in 2009.
Sub-Saharan Africa was able to leverage the experience from other
markets to adopt new business models and avoid legacy infrastructure
(for example, deploying wireless data/voice systems rather than
installing landlines). In the same way, the African energy market can
learn from the recent experience in peer markets around the world to
move past the traditional focus of publicly financed transmission
infrastructure and instead foster a dynamic market place that is driven
by private investment.
A Guide to the Guide
Who is this book for?
This handbook would benefit all stakeholders involved in the power
sector and more specifically in the development of transmission
infrastructure. The book is intentionally designed to benefit all levels
of readers:
Beginner: The book provides an overview of the fundamental regulatory structure
of transmission markets, the planning and procurement of transmission
systems and the core principles of contracting and finance that are
required to attract private investment. The intent is that with this
essential background information in mind, the detailed explanation of
private investment models will be easier to understand.
Utility/Regulator: The observations and guidance in this handbook are presented from the
perspective of a public official in an utility or a regulator.
Specifically, the assumption is that such an official has already
recognised the need to bring private-sector investment into the market.
Further, the book assumes that the official is considering the required
adjustments to the existing regulatory framework and the specific
obligations in any partnership with a private-sector investor to develop
transmission infrastructure.
Procuring Agency/Negotiator: Perhaps the greatest value that we can convey in this book is the
collective experience of the authors in planning, procuring and
negotiating transmission projects. As a result, the book contains
significant detail on the structuring of private transmission projects,
the allocation of risks and obligations within those structures, and
related considerations around financing and regulatory compliance.
In addition to the public sector readers described above, this handbook
should also be helpful to other sector participants including the
transmission companies, transmission system operators, regulators,
investors, and financial institutions as it presents a diverse set of
considerations that those parties must address in their role in the
development of private transmission projects.
Who are the authors?
The knowledge and guidance presented in this book are not intended to
represent the opinion of any one author. As emphasised throughout this
book, the development of transmission infrastructure through a
partnership between the public and private sector requires close
collaboration between stakeholders and the application of expertise from
many disciplines. To hold to this guiding principle, the development of
this handbook also brought together a diverse group of stakeholders and
experts. Our group of authors, who each contributed their time on a
pro-bono basis, includes contributors from governments, development
banks, investment funds, project developers, universities and leading
international law firms. Equally important is that our group includes
engineers, economists, lawyers and regulators who collectively have over
200 years of experience in the energy sector. Our sincere hope is that
the collective wisdom and dedication of this group demonstrates how
important it is to make progress in addressing the infrastructure gap in
Sub-Saharan Africa and that our contribution will make a meaningful
impact on that effort.
How was this book developed?
The unique conditions for the preparation of this handbook are notable
since they differ from the rest of the Understanding series. As with previous books, this handbook was produced using
the Book Sprint method which allows for the simultaneous drafting, editing, and
publishing of a complete book in a short period. For the previous
handbooks in this series, our authors were able to gather together in
the same place and produce a book in five days. Since coming together in
person was not possible under current conditions, our group of authors
instead agreed to come together virtually. In just two weeks, across
seven time zones and through the collective will of our authors (and
generous patience of others in our households), we were able to generate
the same dialogue, critical thinking and joint decision making that had
made the previous books such a trusted resource. As always, there was a
surprising amount of consensus on some topics and an unexpected level of
debate on others. The outcome is a product that reflects this diversity
of opinions rather than the personal opinion of any one author or the
institution they represent.
The authors would like to thank our Book Sprint facilitator Barbara
Rühling for her ability to adapt the Book Sprint process to a
virtual format and for her patient guidance throughout the hours of
staring at our confused faces on a computer screen. The authors would
also like to thank Henrik van Leeuwen and Lennart Wolfert for turning our rushed scribbles into beautiful and meaningful
illustrations. The tireless work of Book Sprints’ remote staff Raewyn Whyte and
Christine Davis (proofreaders), and Agathe Baëz (book design),
should also be recognised. It is also important to recognise the considerable planning and
development that went into the conceptualisation of this handbook before
the drafting process. In particular, our deepest appreciation goes to
Elizabeth Clinch (International Program Specialist, CLDP) for the
original research at the outset of the concept development and for her
tireless work to bring our group together in a virtual space. The
authors would also like to recognise the following individuals and
institutions that helped focus dialogue to build a consensus around the
need for a handbook focused on transmission financing: Jennifer Baldwin
(Power Africa); Megan Taylor (Power Africa); and Kenyon Weaver
(Commercial Law Development Program). The authors would also like to
thank the generous funding and logistics support from the United States
Agency for International Development’s Power Africa programme and
the African Legal Support Facility.
How may I use this book?
To continue the tradition of open-source knowledge sharing that is at
the core of the Understanding series, both as a standalone reference guide and as a jumping-off
point for further discussion and scholarship, the book is published
under the Creative Commons Attribution-NonCommercial-ShareAlike 4.0
International License (CC BY NO SA). In selecting this publication license, the authors welcome anyone to
copy, excerpt, rework, translate and/or re-use the text for any
non-commercial purpose without seeking permission from the authors, so
long as the resulting work is also issued under a Creative Commons
License. The handbook is initially published in English with translated
editions soon to follow. The handbook is available in electronic format
at http://cldp.doc.gov/Understanding as well as in print format. Many of
the contributing authors are also committed to working within their
institutions to adapt this handbook for use as the basis for training
courses and technical assistance initiatives.
How does this book relate to the Understanding Series?
This handbook is the fifth in the Understanding series published by Power Africa. The first handbook, Understanding Power Purchase Agreements, focused on the legal and financial considerations in a Power Purchase
Agreement (the PPA handbook is now in its Second Edition). The second
handbook, Understanding Power Project Financing, focused on the financing structures and mechanisms that can be
employed to finance private independent power projects. The third
handbook, Understanding Natural Gas and LNG Options, was developed by the US Department of Energy and is an in-depth guide
on upstream and downstream development of natural gas. The fourth
handbook, Understanding Power Project Procurementprovided an overview of the mechanisms and strategy behind successfully procuring privately-owned power projects.
Figure 1.3: Cover page of the "Understanding" series (some are also available in Amharic and French)
The Authors
Reason Abajuo
Legal Counsel
African Legal Support Facility (Côte D'Ivoire)
Samson O. Masebinu
Development Assistance Specialist: Energy Finance
USAID/Power Africa (South Africa)
Mohamed Rali Badissy
Professor of Law
Penn State Dickinson Law (USA)
Subha Nagarajan
Managing Director
Global Capital Advisory (USA)
Christopher Flavin
Business Development Director
Gridworks (UK)
Gadi Taj Ndahumba Head of Power Sector
African Legal Support Facility (Côte D'Ivoire)
Jay Govender
Projects and Energy Sector Head
Cliffe Dekker Hofmeyr Inc. (South Africa)
Kaushik Ray
Partner
Trinity International LLP (UK)
Ryan Ketchum
Partner
Hunton Andrews Kurth LLP (UK)
Stratos Tavoulareas
Energy Advisor and Visiting Scholar
George Washington University (USA)
Julius Kwame Kpekpena
Chief Operating Officer
Millennium Development Authority (Ghana)
Omar Vajeth
Principal Corporate Relations Officer
African Development Bank (South Africa)
Mohammed Loraoui
Attorney Advisor (International)
U.S. Department of Commerce (USA)
Resources
Introduction
The business models used to finance transmission infrastructure are
heavily impacted by sources of funding for the sector. Before
introducing the different business models, it is necessary to understand
the various external funding options and their criteria, which this
chapter explores.
In the next chapter 3. Common Funding Structures in the African Market,
we discuss the status quo of transmission infrastructure financing in
the African continent — the public sector structures generally
used to finance these types of projects at present. We then look
to business models involving the private sector in chapters 4. Introduction to Private Funding Structures, 5. Independent Power
Transmission (IPT) Projects, 6. Whole-of-grid concessions, and 7. Other
Private Funding Structures.
Transmission projects will go through a detailed planning phase before
a source of financing and a business model are selected. Chapter 9. Planning and Project Preparation explains this process.
The risks highlighted in chapter 11. Common Risks must also be considered as these will impact sources of funding as well
as business models. The funding decision will have implications for the introduction of the
private sector or continued reliance on public sector funding, and
together these will inform the business model selected.
Below we set out the broad principles of financing that have been or
could be applied to the funding of existing and future transmission
infrastructure projects.
Corporate Finance
Many businesses, especially large businesses in capital intensive
industries, raise debt funding on the strength of their balance sheets,
the stability of their revenues, and their ability to service their
debts. They do not grant security over any part of their assets to
lenders or bondholders, and they agree with each lender that they will
not grant security over their assets to any other or future lenders.
This type of financing — financing that does not
involve the grant of security over a company’s assets — is
referred to as corporate finance.
When considering corporate finance in the context of funding
transmission infrastructure, the relevant entity procuring funding has historically been the
national transmission company of the country. The financial health and liquidity of this entity’s
balance sheet (assets and cash flows) will determine its borrowing
capacity (which can be enhanced with government support). If the credit
of the national transmission company does not allow it to raise debt,
additional support from the government’s balance sheet will be
required to secure external debt.
Project Finance
In a project finance context, the funding is secured against the
viability of a specific project. In this option, a project company is created for financing, constructing and potentially operating the transmission assets and is financed with a mix of equity and
debt. In typical project finance funding structures, the project company
also retains ownership of the transmission asset. A lender considers the
revenue generated by the transmission project as the primary, and often
singular, source of loan repayment. The projected cash flows after
meeting operating expenses must be sufficient to service debt in terms
of capital repayment and interest. The cash flows available after debt
service should also provide a reasonable return on equity.
The predictability, sufficiency and certainty of cash flows will
determine the project company’s borrowing capacity to finance the
project. If the project underperforms and the borrower defaults on the loan as a result, the lender will have the right to enforce its security on the project
company’s assets. If liquidating the project company’s
assets is insufficient to recover the balance of loan owed due to
default, the lender will have no recourse to the owner(s) of the project
company for further compensation: the sponsor's liability is limited
to the investment it has made via its equity contributions.
Therefore, the key to project finance is the underlying revenue
stream generated by the asset in question (e.g., annuity, use of system
or wheeling charges for a transmission infrastructure project).
If the transmission asset is not linked to a dedicated generation
facility or a large industrial consumer, and there is uncertainty as to
how well-utilised the transmission infrastructure will be, lenders will
expect a payment regime similar to a fixed capacity payment or fixed
availability payment. Such payments are not vulnerable to changes in the
amount of power flows on the transmission line.
Corporate Vs Project Finance
Balance sheet flexibility
In the context of transmission infrastructure, an entity’s
borrowing capacity via corporate finance is limited by its existing
balance sheet, including how much existing debt it has (and the state of
its revenues and assets). Any existing balance sheet constraints will
limit the borrowing capacity of transmission utilities to fund transmission infrastructure using corporate finance structures.
The state utility may have the opportunity to borrow further with
government support. Project finance structures, however, do not look at
the transmission company’s borrowing capacity because the debt
capital raised is treated as off-balance-sheet financing.
Cost of funds
Under corporate finance, since repayment is divorced from a
transmission asset’s underlying economic value or performance,
repayment risk will be a function of a borrower’s existing level
of leverage compared to the financial or market value of its total
assets to determine its liquidity. A healthy balance sheet will attract
a lower cost of financing (more efficient pricing). As the credit
quality of an entity decreases, the cost of funding increases due to
higher risk perception.
Under the project finance option, since repayment is secured via
project revenue, lenders will focus on mitigating all risks to those
cash flows. Project finance transactions tend to be highly structured
and complex, with emphasis placed on appropriate contractual allocation
of risks that impact the underlying revenue stream. This adds to the
time and cost of pulling together the number of stakeholders and related
documentation. The pricing of the project is influenced by the perceived
risk of the cash flows, the credit quality of the source of those cash
flows, and if needed, the enhancement of these cash flows.
Business model considerations
Transmission networks require ongoing investment. Ongoing investment
requires continuous capital injections in the business in the form of new projects or
upgrades of existing assets. As a general rule, state-owned transmission utilities, whole-of-grid
concessionaires, or privatised utilities will typically find it more
practical to raise debt financing using corporate financing techniques.
In contrast, a project company established to implement an independent
power transmission (IPT) project will use project finance to allow for higher
debt to equity ratios, longer tenor, and limited recourse for the
shareholders in the project company. Given these factors, IPTs are
likely to be financed using project finance techniques.
Sources of Capital
The sources of capital for a transmission project will depend upon the
outcome of the planning, risks related to the project, and a government’s and state
utility’s balance sheets and the ability to raise finance.
In chapter 3. Common Funding Structures in the African Market, the existing model of government balance sheet financing for these
assets is discussed in more detail, and in later chapters, we discuss
some private sector finance models. Below, we set out the typical
capital sources — government budgetary allocation, debt, and
equity — and indicative terms used in most funding models.
Government budgetary allocation
In the context of its annual budget, a government may choose to
allocate a certain amount of the fiscal budget to the development of the
country’s transmission infrastructure. When an allocation is made,
the specific method of application of these funds is likely to vary from
one government to another depending on the country’s laws and
conventions for public procurement of infrastructure. In some
jurisdictions, the funds will be managed and applied directly by the
Ministry of Energy (or equivalent); in others, they may be channelled
via a department of public works or the state-owned entity licensed to
construct and maintain transmission infrastructure. Nonetheless, the
source of these funds will invariably come directly from the
government’s accounts or “balance sheet” as shown
below, and thus the government’s ability to finance transmission
infrastructure through a budgetary allocation will depend on the
country’s priorities and fiscal constraints. Ultimately, the
decision as to whether to use this model will depend on the
government’s balance sheet (i.e. availability of cash) and its
expenditure priorities (based on its current policies) given a
country’s wider infrastructure investment needs.
Figure 2.1: National budget approach to funding infrastructure
project
In practice, financing transmission infrastructure through budgetary
allocations is difficult and has become increasingly rare. The size of
the investment puts significant pressure on a government’s budget
and its available cash. The allocation can be structured in a way as to
accumulate yearly until reaching the required amount, but depending on
the size of the investment, the desired amount may take many years to be
collected. Furthermore, in addition to slowing down the development of
the power grid, this approach requires significant fiscal discipline as
the government needs to set aside the funds each year and resist the
temptation to use them when a crisis or economic downturn arises.
Debt
Transmission infrastructure necessitates long-term funding, given the
relatively high capital expenditure required for identification,
development and construction. Given constraints in local commercial
banking markets, public financial institutions are an important source of debt financing
for transmission infrastructure.
The stakeholders and financial products described below cover both
public and private sector debt financings — their application in
real-world scenarios is dealt with in later chapters.
Concessional funding for balance sheet financing
Multilateral development banks (MDBs) and donor-backed funds can lend
directly to governments on concessional or grant terms for identified
projects which follow the MDB procurement guidelines, and can also be
lenders for the financing of independent power transmission projects in
the private sector.
Examples of MDBs, which provide concessional finance, include the African Development Bank, European
Investment Bank, and the World Bank Group. Concessional in this context means that the terms of the loan are likely to
include low or subsidised interest rates, extended grace periods, and
long amortisation schedules that can extend beyond 30 years. Typically these loans are provided to the government
via the Ministry of Finance, and on-lent to the transmission
utility. These loans are accounted for on the government’s balance
sheet, typically as both an asset and a liability. The transmission
company will own the asset, but repayment, if required, will be secured from
the government's balance sheet. MDB and donor concessional money may
be used to settle contractor invoices directly, but the government
remains the obligor.
Transmission projects funded through MDB concessional funds can in some
instances take longer to secure the funding and the necessary
contractors. This is often the case where the government or the utility
does not have the necessary capacity to manage the high degree of
coordination, planning, and adherence to MDB procurement guidelines for
such projects. In addition, MDBs have country and sector limits (often
called “funding envelopes”) that are available to countries for this type of financing support
which get revised based on the country’s capacity for debt and the
requirements of the ministries. When the funding envelopes may be
nearing their limits, countries will have to prioritise the
infrastructure projects they want to support. Bilateral donor agencies
can be another source of grant or heavily subsidised financing which can
provide sector viability gap funding or support to an individual
transaction.
Figure 2.2: Relationship between parties in a concessional funding for balance sheet financing
Private sector MDB funding
The same MDBs have “private sector windows”, i.e., funding
available for private sector projects, such as IPTs. These are
loans granted on commercial terms rather than concessional terms, and
for tenors up to 18-20 years. Importantly, private sector MDB loans are
not captured on the government’s balance sheet, unless a
government guarantee or financial backstop helps secure repayment. The structures under which MDBs participate in IPTs are set out further
in chapter 5. Independent Power Transmission (IPT) Projects.
Export Credit Agencies (ECA)
Export Credit Agencies (ECA) are institutions that are publicly
owned financing agencies that help finance national exports by providing direct loans,
guarantees, or insurance to overseas buyers, including entities such as
transmission companies. ECA finance can be used in the public sector, in
government balance sheet financing, and project finance involving IPT
structures.
Examples of active ECAs in Sub-Saharan Africa include the Export Credit
Insurance Corporation of South Africa, US Export-Import Bank, UK Export
Finance, BPIfrance, SERV from Switzerland, Euler Hermes from Germany,
and the Export-Import Bank of China. Some of these agencies can provide
local currency solutions in certain jurisdictions, but for the most
part, provide USD and Euro denominated loans.
To ensure financing discipline and promotion of fair and transparent
trade practices, financial terms and conditions follow guidelines set by
the OECD, called the OECD Arrangement on Officially Supported Export Credits
guidelines. Eligible financing is typically up to 85% of the relevant export
contract, with some allowances to cover a portion of local on-shore
costs, but the expectation is that the government (or borrower) covers the
15% balance, usually in the form of a down payment in cash. Financing
terms include longer tenors than commercial banks can competitively
price or sometimes provide to borrowers in certain jurisdictions
(up to 12 years for corporate finance and 14 years for project
finance loans), but the cost of funds is generally more expensive than
concessional borrowing. For transmission infrastructure associated with
a renewable energy generation project, the OECD Arrangement allows
project finance loans up to 18 years, on an exceptional basis.
In the context of transmission infrastructure, ECAs can provide (1) corporate finance loans, underwriting the
sovereign’s capacity to repay the loan, lending directly to
Ministries of Finance, which helps to reduce the cost of financing, and
(2) project or corporate finance loans to IPT special purpose vehicles
(SPVs) or private companies, respectively.
Depending on the ECA, they can either lend directly or insure/guarantee (between 95-100%) a commercial bank that will provide
funding, which will be reflected in the commercial bank’s lower
cost of funds to the project.
Figure 2.3: Relationship between parties in an Export Credit Agency funding structure
Development Financial Institutions (DFIs)
Development Financial Institutions (DFIs) which include MDBs, are usually majority-owned by national
governments and source their capital from national or international
development funds, or benefit from government guarantees. This ensures
their creditworthiness, which enables them to raise large amounts of
capital from international capital markets and provide financing on very
competitive terms. DFIs can provide up to 15 to 20 years, long tenor
competitive commercial lending to projects with some degree of private
ownership. Some examples of DFIs active in Sub-Saharan Africa include
the Development Bank of South Africa, Development Finance Corporation
from the US, the CDC group from the UK, Proparco from France, and FMO
from the Netherlands.
Some DFIs can provide loans to state-owned utilities which demonstrate
independent governance, depending on that utility’s balance sheet
and ownership of assets. All DFIs can provide commercial project finance
debt to a project company, which can be used in IPT transactions. The diagram below shows a DFI-funded project finance structure.
Figure 2.4: Relationship between parties in a Development Financial
Institution funding structure
In addition to lending, some DFIs such as the AfDB and the WBG can
offer a guarantee and insurance products to help credit enhance a
project structure by covering off certain credit or political risks.
Guarantees include partial credit guarantees (PCGs) and partial risk guarantees (PRGs) to cover commercial lenders and investors against the risk of a
possible government failure to meet contractual obligations to a
project. Please see the UnderstandingPower Project
Financing handbook, section 7.2 for an in-depth discussion of PCGs and PRGs.
Some DFIs provide political risk insurance (PRI) to mitigate and manage risks arising from the adverse action, or
inactions, of governments that go against contractual obligations. PRI can also be used to backstop termination support under a government
guarantee or other forms of government undertakings if the government is unable to pay as per its contractual obligation.
Green/climate-backed financing
There are many clean technologies and climate change donor-backed funds
which can provide grant funding to support grid modernisation and
transmission lines, if the infrastructure can be linked to projects and
initiatives which promote and advance sustainable development and
encourage the development of a more sustainable economy, for example,
renewable energy generation. Given the emphasis that many countries are placing on decarbonisation
to support countries on their journey to a green energy transition, it
is expected that the EU and other publicly backed institutions will make
more grants or highly concessional finance available to support these
activities.
The advantage of these resources is that they provide subsidised
financing, which, when combined with more commercial sources of funds,
can help blend the cost of capital to reduce financing costs for
transmission infrastructure.
Transmission is the enabling infrastructure for renewables, and, as
such, it should be credited with greenhouse gas reductions and be
eligible for green financing. In addition, the strength of the existing
transmission and grid networks will determine how much greenfield
renewable energy generation a country can support. Many emerging
countries with mandates to significantly scale up renewable energy
generation will need to simultaneously invest in upgrading and expanding
their transmission network to support greater renewable energy
penetration. While this is still an evolving field, greenhouse gas
reduction calculation methodologies have been considered by numerous
organisations and both governments and developers should monitor
progress to identify potentially attractive financing options.
Commercial Banks
In addition to DFIs, commercial banks provide debt financing to
transmission infrastructure projects. Commercial banks are
privately owned banks that participate and provide funding to a range of
projects, including transmission projects. Commercial banks more
typically lend to projects that have creditworthy cash flows or cash
flows that are enhanced with cover via DFIs or ECAs.
Typically, commercial banks are financial institutions that are
regulated by central banks and other international banking regulations
which impact the level of liquidity, risk thresholds and pricing.
Blended finance
Providing hybrid private sector/donor funding for IPTs, for example,
can significantly boost the availability of funding to the sector.
The provision of grant funding for a project is unlikely to impact
returns for investors positively or negatively since funding models for
this asset class are typically fixed or capped. The impact of such
funding would be to increase the number of projects which can be
undertaken.
Equity
In IPT and other project finance structures, lenders generally require
project owners to invest an amount of equity in exchange for shares in
the project company, usually for at least 20-30% of the total project
cost. This form of long-term capital earns dividends over the life of
the project which are paid from the remainder of cash flows after
operating expenses and debt service obligations have been met. The
capital structure and cash waterfall are intentionally aligned so that
equity owners are incentivised to ensure that the transmission assets
are constructed and perform as contractually specified, to generate and
collect the forecasted revenue. Equity providers for transmission
infrastructure include:
Developers/Contractors: This includes developers or engineering, procurement and
construction (EPC)/original equipment manufacturer (OEMs), who develop, build, and/or operate transmission assets and are
interested in providing equity and/or subordinated debt in an
underlying project if the long term economics are sufficiently
attractive.
Infrastructure funds: There are many infrastructure funds or DFI-funded investment
vehicles with a mandate to invest in the energy sector, which can
include transmission infrastructure.
Development Finance Institutions: A few DFIs can provide equity
funding for various types of power projects so long as the long term
economics are sufficiently attractive.
Industrial sponsors: This includes sponsors who invest in the
construction of dedicated-use transmission infrastructure to support
their core business or power generation plants, such as mining
companies.
In some instances, state-owned transmission companies or energy
utilities also invest capital (or some other form of consideration) into
a project company and acquire equity interest.
Summary of Key Points
Corporate Finance is a way for an entity to secure an external debt
by leveraging its balance sheet. The financial health and liquidity of
the entity’s balance sheet will determine its borrowing capacity.
Project Finance allows an entity to raise external finance on a
non-recourse basis where loan repayment is secured by cash flows
generated by a project company’s assets.
Key considerations between raising debt via corporate or project
finance structures include (1) creditworthiness of the obligor, which
will determine the cost of funding and whether additional payment
security is required, and (2) business model procurement strategy.
The most traditional source of capital to fund transmission
infrastructure has been the government’s balance sheet.
Sources of external funding to support government borrowing include
bilateral donors, MDBs, and ECAs.
External funding for IPTs and whole-of-grid concessions
include DFIs and ECAs, along with commercial banks, generally with
some form of credit enhancement from DFI or ECA guarantee or insurance
product.
Green/Climate-backed financing can provide meaningful blended finance
and viability gap funding for grid modernisation, critical for
emerging markets who need to strengthen their transmission and grid
networks to support greater renewable energy penetration.
There are providers of equity in the power generation space who could
provide equity in IPTs assuming the economics and returns of the
project are sufficiently attractive.
External funding sources and their criteria can impact the
business model a government chooses in procuring new transmission
infrastructure.
Introduction
The purpose of this chapter is to introduce some private sector
business models which have been applied to finance transmission
infrastructure in other parts of the world. More detailed information on
the different funding structures will be provided in the following chapters which dive into the details of each model. This chapter aims to provide
tools to ensure that well-informed decisions can be made. More
specifically, we will look at key considerations in determining whether
these business models are, or could be, applicable in a particular
country or market.
Which model is more suitable for a country or a specific project
depends on many factors which are country and project-specific. A
detailed assessment is recommended to identify all the relevant
considerations and provide the advantages and disadvantages of the
various options, so the government can make the best decision.
Nevertheless, whilst private sector involvement in the transmission sector can take
many forms, this book will discuss:
Independent power transmission (IPT) projects (in chapter 5)
Whole-of-grid concessions (in chapter 6)
Privatisation (in chapter 7)
Merchant lines (in chapter 7) and
Industrial demand-driven models (in chapter 7)
The two most applicable structures to the African context based on the
current state of its electricity supply industry are the IPT and the whole-of-grid concession. For this reason, more details will be provided on these two
models than on privatisation, merchant lines, and industrial
demand-driven models.
Key Considerations
Ownership, control, and maintenance
An obstacle to privately financed transmission infrastructure is
often the perception that the national power company or transmission
system operator (TSO) will lose control over the sector. On the
contrary, in many cases, the private investor builds the transmission project and
turns over the operation of the assets to the TSO immediately upon
completion of construction and project acceptance. In other cases, the
private investor only owns and operates physical transmission assets
without managing the electrical system and coordinating generation
dispatch and power flows.
Another important consideration is that ownership and control do not
have to be held under the same organisation. Who owns the transmission
infrastructure may vary depending on whether it is an IPT or a whole-of-grid concession. It is also possible to find variations within the same model. For
example, an IPT may be entitled to own the infrastructure which it
constructs on a long-term basis, but it may also be a condition of the
project documents or a condition of the relevant licensing regime that
ownership of the assets is transferred to the state-owned utility or
another state-owned entity at the end of a fixed period.
Furthermore, operation and maintenance can be separate as maintenance
of the transmission assets (under the project) can be carried out by the
private investor or a maintenance contractor or even be subcontracted to
the national transmission company.
Depending on the objectives of the government, it is, therefore,
possible to calibrate the degree of control retained in respect of the transmission
asset as well as define the ownership of the asset during and after
the duration of the core agreement.
Financing and risk allocation
Although there are many advantages to private funding, the nature of
the financing will also carry constraints and requirements. When
choosing a private funding model for financing transmission
infrastructure, a government must be aware that it will require efforts
in negotiating a complex commercial transaction often driven by
well-established market standards. This is especially true when it comes
to project finance which is typically the method of financing for
IPTs.
Risk allocation is the key component of project financing and by
extension may determine the success or failure of the privately-funded
transmission project. While there is a natural tendency to attempt to shift risks to other
parties, it is wise to keep in mind the golden rule of risk
management: Each risk should be allocated to the party that is in the best
position to first control/reduce it and then manage it. Imposing risks on the private investor, even though it is not in
the best position to manage them, will typically result in a more
expensive or even unbankable project. Allocating the risks to the party which
is in the best position to manage them will help to de-risk and reduce
the overall cost of the project and the final tariffs.
Regulatory framework
There may be concerns that the legal/regulatory framework may not be ready for some forms of
private investments. Although this may be a genuine challenge, it is not
an insurmountable obstacle. It is usually possible to put some of these models in place
within existing frameworks. If legal change is required, the project
could be structured to address the lack of laws/regulations (regulation by contract) and can be used as a testing ground to learn from and ensure that the
laws/regulations which are finally approved are the right ones for the
country.
Approach to Risk Allocation
As is the case with all power projects, transmission projects have many
risks, some unique to transmission and others similar to all power
projects. The most challenging risks in private transmission projects are: 1)
land acquisition (“rights-of-way”) and 2) securing the
revenue stream.
While each country and project have their own uniqueness which needs to
be taken into account, some important lessons learned have emerged from
the numerous transmission projects that have been implemented so far:
Consider carefully (and with an open mind!) what organisation is in
the best position to acquire land and secure
“rights-of-way”; it may be the developer or a government
entity. Whoever takes the responsibility may need support from a
third organisation (e.g., a multilateral bank).
Environmental and social issues should be identified from the
earliest stage of project development and be addressed in the best way
possible. Extensive public consultation is essential and often helps
to overcome key obstacles.
Keep the project simple! For example, in the case of an IPT, an
annuity payment linked to asset availability is preferable (for all
parties).
Securing a revenue stream to the project may require some creativity
if the sector is not financially viable. There is a lot of experience
on how an acceptable structure can be designed to address the specific
needs of each project. Escrow accounts, project finance waterfalls,
offtaker guarantees, and others could be deployed as necessary.
We would further note that countries that have successfully delivered
IPPs may well choose to replicate some parts of the documentation
structure of IPP models into the transmission sector. This may inform,
for example, how the risk allocation between the government and the
private sector is documented. In countries where political risks are
taken by the government by way of a put/call options agreement (PCOA)
for example, this documentation method may be replicated in the
transmission sector. In other countries, political risks are dealt with
in an “implementation agreement” or “concession
agreement” and government officials may be more comfortable with
both the nomenclature and risk allocation set out in these documents, as
negotiated in the IPP space.
While it is important to be efficient and not “reinvent the
wheel”, it is also crucial to take a fresh look at how risks are
allocated as there may be particular differences in the risk allocation
agreed in that country on the generation side that does not apply to the
transmission side, due to the specific nature of a particular project.
The Role of Key Stakeholders for Privately Funded Structures
The private developer/investor can be responsible for some or all of the project preparation,
design, financing, construction and operation of the project. Depending
on how and when the project developer will come on board, it may have
substantial project preparation activities to complete. This
depends on the procurement approach to select the developer/investor
(competitive bidding or sole source).
Financing will typically be provided by other organisations too,
including equity and debt. The financial institutions will carry out due diligence of the project including review of the
various contracts, as well as assessment of the risks and project
“bankability”, ahead of financial closure. At financial
closure, the lenders will commit to the project and their funds will be
drawn down to fund construction.
The government may have a substantial role to play in the transaction,
especially if the project is not commercially viable. The risk
allocation matrix in fact should determine the role of each project
stakeholder including the government. In an IPT, the investor and
the government may enter into a Government Services Agreement (GSA)
which supplements the agreement between the investor and the
offtaker.
Often, the Multilateral Development Banks have a substantial role to play. In the case of a financially
unsustainable power sector, the government might work closely with the
MDB to develop a roadmap to power sector sustainability. This roadmap
could be developed in parallel with the project but it should include
specific milestones which should be monitored and may be linked to the
project agreements. Also, the MDBs may provide:
Financial and technical support for project planning (including power
system planning, project feasibility studies, ESIA, etc. —
see chapter 9. Planning and Project Preparation)
Review and improvement of the legal and regulatory framework
Support in land acquisition
Guarantees required to secure project cash flow and offtaker
risks
Political and force majeure risk coverage
Last but not least, bilateral organisations and donor agencies could play a catalytic role too. They may help with
technical assistance in project planning activities, but also they may
provide grants or concessional lending because the projects fulfil an
important role in the country’s economy. Also, they may provide
funding to close the viability gap (e.g., similar to KfW’s GETFiT programme). In this way,
scarce grant funding can be used in a targeted way to unlock larger sums
of private sector investment. Private sector procurement and
management practices can also benefit projects which may otherwise have
been solely donor-led or implemented by transmission utilities with
capacity shortages or governance shortfalls.
Providing hybrid private sector/donor funding for IPTs, for example,
can significantly boost the availability of funding to the sector. The
provision of grant funding for a project may not have a positive or
negative impact on investor returns since funding models for this asset
class are typically fixed or capped. The impact of viability gap funding
like this would simply increase the envelope available to multiply the
number of projects which can be undertaken.
The purpose of this chapter is to set out, in a non-exhaustive fashion,
some of the common methods of funding transmission infrastructure that
are currently used on the African continent and to highlight some of
their features.
Most of these funding methods are public-sector led. However, they are
akin to corporate finance structures as the financing is based on the
strength of the government or state-owned utility balance sheets and not
on the viability of the cash flows from the transmission projects
specifically. These methods include government borrowing/ECA financing
and state-owned utility borrowing. Of these methods, government
borrowing and ECA solutions (which also require a government guarantee)
are by far the most common funding structures utilised.
The most common private sector-led funding method used for transmission
projects on the continent is the wrapping up of the financing of the
transmission project into a related IPP project. This method, discussed
in this chapter as the generation-linked transmission model, is the
closest to project financing for transmission projects on the continent.
As will be discussed in detail in this chapter, the cost of the
transmission project is included as part of the construction costs of
the IPP project. Since the IPP project is funded using a project
financing structure, the costs of the transmission project are typically
recouped from the cash flows of the IPP project.
Public Sector-led Funding Structures
Government borrowing
From one country to another, the names of ministries are likely to vary
and their functions can be separated differently among fewer or more
ministries (e.g., the functions of the Ministry of Finance in one country may be shared
between the Ministry of Economic Planning and the Ministry of Finance in
some other countries). For this chapter, the Ministry of Finance (MoF) refers to the ministry (or ministries) responsible for raising and
collecting both foreign and domestic revenues, managing the budget
process and cash resources, setting fiscal policies and forecasting
government revenues. The MoF is also responsible for borrowing on behalf
of the government and managing the purse strings, which sometimes
requires limiting the spending by which ministries try to deliver on their
respective policy goals.
In a funding structure using government borrowing, the MoF effectively
serves as the borrower on behalf of the government. The borrowed funds
will be used for the procurement of the transmission infrastructure and
the government accounts will reflect a new debt. Once the funds are
borrowed, the government can choose to either procure the transmission
line itself or, in turn, lend the borrowed funds to the transmission utility which
will procure the transmission infrastructure and repay the government
from its revenue (diagram below). Even for the latter scenario, the government remains responsible
for the entirety of the debt and will have to pay its lenders even if
the transmission utility fails to repay the government.
Figure 3.1: Simplified model of government funding of infrastructure
project with borrowed funds
On the African continent, the government is most likely to access
financing for transmission infrastructure via concessional borrowing or ECA financing. The borrowed funds are used to procure and pay an EPC contractor to
construct the specified transmission infrastructure. As explained in the
funding chapter 2. Financing Structures and Capital Sources, MDBs and ECAs can lend to a government via the Ministry of Finance to
fund capital expenditure costs. The Lake Turkana Transmission Line case study described below
illustrates the use of concessional borrowing and ECA financing for the
construction of a transmission line.
Case Study — The Loiyangalani–Suswa High Voltage Power Line
(“Lake Turkana Transmission Line”)
Figure 3.2: Schematic of the Lake Turkana Wind Project Transmission Line
The Lake Turkana Transmission Line starts at the 310 MW Lake Turkana
Wind Power plant in Marsabit County, Kenya, and runs south for
approximately 428 km to the KETRACO substation in Suswa, Narok county,
approximately 100 km west of Nairobi. In 2010, the Spanish government
offered to finance the construction of the double circuit line.
This included a concessional loan (for 30 years, with a low
interest rate) of €55m and a commercial credit in an equal amount
offered by the Spanish ECA (with commercial lending sitting behind
it).
Figure 3.3: The original relationship among parties in the Lake Turkana
Transmission line project at the time of commissioning of the line
The Kenya Electricity Transmission Company (KETRACO), created in 2008,
agreed to partly fund the line and substation by way of a tolling
agreement with Kenya Power. With a large dedicated generation project
attached, the potential for future generation projects alongside the
transmission line corridor (an area with geothermal power potential) and
the possibility for the line to interconnect with the Kenya-Ethiopia
interconnector, the economic case for the project was clear.
Interface risk and cost overrun
The initial Spanish EPC contractor who was awarded the contract to
construct the transmission line faced many implementation challenges,
including a protracted wayleave and land acquisition process for which KETRACO was responsible, which delayed construction
works. The initial Spanish EPC contractor subsequently filed for
bankruptcy. The transmission line was eventually completed by a
consortium of Chinese firms and officially commissioned in July 2019,
behind schedule with a $96M cost over run ultimately financed from the government's balance sheet. The
Lake Turkana Power Plant had already been commissioned in September
2018, earning deemed energy payments while waiting for the power
plant’s connection to the grid to deliver energy to the wider
Kenyan grid via the newly constructed line.
Given the Lake Turkana Wind Power project was an IPP and fully
developed by the private sector, it raised an interesting discussion of
“project on project” risk, with the two projects entirely
interdependent but financed by separate means, and the former through
commercial sources with the latter via sovereign borrowing. The risk
allocation between the various stakeholders was heavily negotiated, with
the Government of Kenya (GoK) bearing the responsibility for the timely
delivery of the transmission line. The AfDB provided a €20 million
PRG to backstop GoK’s completion risk on the transmission line,
providing comfort to the Lake Turkana Wind Power lenders that deemed
energy payment obligations would be met in the event the transmission
line commissioning was delayed.
The Lake Turkana cost overruns highlight the magnitude of the interface
risk for interdependent projects. For this reason, transmission lines
are often wrapped in the financing and scope of a generation project.
Further in this chapter, we discuss generation-linked transmission
projects for which it was decided to finance and construct the
transmission asset via the same project to significantly reduce the
interface risk.
Government debt sustainability
The financing of transmission infrastructure from government borrowing
is an attractive method of funding as it can produce favourable terms
(e.g., low-interest rate, long repayment period, etc.) provided the
government can afford the debt. This type of loan is not extended based
on the transmission utility's ability to secure the necessary income
to repay the loan but on the government’s fiscal ability to
collect sufficient revenue to service and repay the debt. It, therefore,
provides more flexibility and allows the government to rely on its full
fiscal revenue for the development of the power sector.
Nonetheless, this method of funding requires careful management of the
impact of the borrowing on the country’s debt sustainability
efforts. Hence, the transmission project will have to compete with other
projects as it will ultimately affect the country’s ability to
borrow for other sectors of its economy. Moreover, the government will
have to ensure that the transmission infrastructure will ultimately
improve the viability of the sector as a series of uneconomical
transmission financing can easily drain the government’s finances
and have long-lasting repercussions on the overall economy. Furthermore, government balance sheet funding may be restricted by
other international geopolitical factors as most government borrowing in
SSA is provided by other governments, government agencies and
MDBs.
State-owned utility borrowing
Countries with energy sectors that can independently recover their
investment and operating costs have state-owned utilities that require
minimal government subsidies or interventions to stay financially
solvent. There are only a handful of state-owned power utilities in SSA that are sufficiently creditworthy to allow them to borrow from
external sources. The repayment of the loan is not necessarily linked to
the performance of the underlying asset that has been constructed but
secured against other sources of income or revenue generated by the
state-owned utility. The state-owned utility borrowing can be from ECAs
and DFIs or the capital market.
An ECA and some DFIs can lend directly to the state-owned utility to
fund the capital expenditure (CAPEX) requirements of a specified transmission infrastructure project,
securing repayment against the utility’s balance sheet. Whereas
the DFI will be agnostic on sourcing, as described above, the ECA will
finance and disburse against invoices for a specified EPC scope of work
which shows equipment and services from the ECA country.
Further, a creditworthy power utility responsible for transmission
assets may choose to raise a corporate bond from capital markets for
general-purpose borrowing, and then use a portion of those proceeds for
investment in new, or the rehabilitation of existing, transmission
infrastructure. An example of state-owned utility capital market
borrowing is provided in the following case study.
Case Study — Caprivi Link InterConnector
NamPower, Namibia’s national power utility, is responsible for
generation, transmission and energy trading, reporting up to the
Ministry of Mines and Energy. Its favourable and independent financial
credit rating has allowed it to raise financing from the capital markets
for its long-term projects.
In 2007, NamPower successfully dual-listed a $3B Namibian
dollar-denominated long-term debt issue on both the Namibian and South
African stock exchanges to fund the Caprivi Link Interconnector
connecting Namibia to the Zambian and Zimbabwean electricity networks by
2009. Notable features at the time included a 300MW bipolar scheme,
upgradeable to 600MW, and comprising a 951 km 350kV high voltage direct
current (HVDC) bipolar line, along with numerous substations. This
represented the first cross-border debt-raising transaction completed in
Southern African capital markets, to finance a cross-border
interconnection in line with the Southern African Power Pool (SAPP) with
the objective to interconnect all Southern African Development Community
(SADC) countries.
Figure 3.4: Corporate borrowing from ECAs or DFIs a case of Caprivi Link project
Features of Public Sector-led Funding Structures
Ownership and control
Government-supported financing is the most common approach to financing
transmission infrastructure projects in Africa. Government balance sheet
financing supports infrastructure ownership and controls being retained
by the government and/or the relevant transmission utility, thereby
increasing the asset base of, and sources of revenue, for the country. In
addition, the government or the transmission utility remains in full
control of the technical designs, timelines and process in the
development of the transmission infrastructure.
Where the transmission utility maintains ownership of the transmission
infrastructure, it also bears the risk and responsibility for the proper
management and maintenance of the infrastructure. This extends to:
Proper planning and management of outages
Regular and prudent maintenance
Minimising losses due to theft or disrepair
Swift reaction to repairs, defects, and emergencies
Matters relating to security and insurance
This often results in significant reserves being required to meet the
costs of such obligations.
Balance sheet impact
Public sector-led funding structures will affect the balance
sheets of both the government and the utility. Such funding structures also
affect the extent of the government’s debt sustainability. Hence,
these structures require significant fiscal discipline.
Private Sector-led Funding Structure
Generation-linked transmission projects
There are examples of transmission infrastructure that is built by an
IPP developer as part of a generation project. Generation power projects
tend to be located as close as possible to fuel sources (river, coal
mine, solar radiation, etc.). However, especially for renewable
projects, the fuel sources are often far from existing grid connections
and may require the construction of additional transmission
infrastructure including substations. When procuring a new generation project,
the government or the transmission utility may therefore decide that the
transmission infrastructure is to be built by the IPP as part of the
broader generation project and handed over to the government. Depending
on the developer’s appetite and the size of the transmission line
asset, the IPP might be interested to accept to take on the construction
(and potentially financing) of a transmission line that will connect its
project to the grid. Nonetheless, since the transmission line is
transferred to the utility at some point in the project, the
transmission line is ultimately will be government-owned.
This kind of model is used to reduce the connection risk in IPP
projects. This ‘connection risk’ is the risk that the IPP or power plant is producing (or able to
produce) electricity but cannot deliver it to end users because of a
lack of connectivity to a transmission line. This could manifest itself
in the construction phase of the power generation project where the
delay in the construction and completion of the transmission
infrastructure in turn delays the achievement of an anticipated
commercial operations date under the power generation project.
This model allows the IPP to be in control of the interface risk between the two projects — generation and transmission. If this
risk is not managed in this way, the typical remedy to the IPP is the inclusion of “deemed
energy” payments under the power purchase agreement. These are
payments calculated based on the loss of revenue from the energy that
would have been delivered but for the transmission line unavailability
event. Where generation is in the private sector but transmission is in
the public sector, there is an increased financial risk on the
government to pay these “deemed energy” payments (e.g., see above Case Study — Lake Turkana Transmission Line) to
the extent the government or transmission utility does not manage or
deliver the transmission infrastructure or make it available for the IPP
to use.
The extra equity investment and debt funding necessary for the
supplemental transmission work can either be repaid via a cash payment
by the transmission utility when the transmission infrastructure is
handed over or can be compensated through a higher generation tariff
which reflects the additional fixed cost incurred to connect the power
project to the national grid. The transmission asset will typically be
handed over to the transmission utility at the commercial operation
date, even if the cost of the construction is repaid to the IPP through
the electricity tariff under the PPA.
Some considerations that arise when transmission infrastructure is
built and captive to the benefit of one beneficiary (closed access for
other usages) but which is ultimately handed to the transmission utility
to maintain via public funds, is whether the transmission line still
serves the greater public good. This may still be the case if the
captive line provides reliable electricity to industrial users, who have
wider economic benefits for a country.
Case Study — Self-build funding model in the South African IPP
programmes
The South African government, through its energy ministry, has
undertaken the competitive procurement of many independent power
producer (IPP) programmes across various technologies since 2010. One of
the most lauded of these programmes is the Renewable Energy Independent
Power Producer Procurement Programme (REIPPPP). Today REIPPPP is in its
fifth round of procurement. As of the end of round 4 bidding, the South
African power utility Eskom Holdings SOC Limited (Eskom) concluded PPAs
for 92 renewable energy projects with a total capacity of 6327 MW. Grid
connection and integration of the power generation facility to the
national grid was a key feature of the REIPPPP.
Facing Eskom funding constraints and the short timelines required for
grid connection, the REIPPPP was structured to allow bidders to elect to
build the grid connection facilities on a "self-build" basis
as part of their bid. The option was initially only made available for
distribution facilities but in the second quarter of 2015, Eskom's
transmission division introduced a self-build option to its customers,
both electricity generators and consumers.
In this option, the customer can elect to design, procure, construct
and commission the transmission assets. The customer undertakes the
design, route selection and procuring of all authorisations, with
consultation and the approval of Eskom, who ultimately ensures the
transmission infrastructure aligns with existing grid technical
specifications. After successful commissioning, the customer is obliged
to transfer full ownership of the transmission assets and all
environmental authorisations, wayleaves, approvals and permits to Eskom.
Eskom states in its Transmission Development Plan published in January
2021 that the intention is to give customers greater control over risk
factors affecting their network connection. However, it is important to
note that transmission infrastructure expects that it is open access,
meaning there could be the possibility of connecting other generation
assets and other customers to the self-build transmission line after it
is handed over to Eskom.
The self-build option has since also been expanded to allow customers
to also build associated works (such as substations) that will be shared
with other customers, based on an assessment by Eskom of the
accompanying risks to the transmission system and other customers. Since
this is purely a voluntary option, the option of Eskom constructing the
generator or customer's network and paying a connection charge also
remains available to bidders and customers alike.
What is important to note with this option is that the customer bears
the risk and responsibility to finance the transmission infrastructure
construction works, including the authorisations required and the
wayleave acquisition (including compensation). These costs are recovered
through the tariff over the term of the PPA, so IPPs need to consider
these additional costs when bidding into the tender.
Due to the success of the self-build option, this approach has been
adopted by the South African government in all subsequent IPP
programmes.
Summary of Key Points
Most existing funding methods of transmission infrastructure in
Africa are public-sector led.
They are akin to corporate finance structures as the financing is
based on the ability of the government to raise financing and not on
the viability of the cash flows from the transmission project
specifically. Of these methods, government borrowing and ECA solutions
(which also require a government guarantee) are by far the most common
funding structures utilised.
The most common private sector-led funding method used for
transmission projects in SSA is the wrapping up of the
construction and financing of the transmission project into a related
IPP power generation project.
Government-supported financing is the most common approach to
financing transmission infrastructure projects in Africa. It can be an
attractive method of funding as it can produce favourable terms (e.g.,
low-interest rate, long repayment period, etc.) if the government can
afford the debt.
There are examples of transmission infrastructure that are built by
an IPP developer as part of a generation project. Depending on the
developer’s appetite and the size of the transmission line
asset, an IPP might be interested to take on the
construction (and potentially financing) of a transmission line that
will connect its project to the grid.
This chapter will discuss the Independent Power Transmission (IPT) model, the scope of which involves the design, construction, and financing of a single
transmission line or a set of transmission lines and/or associated
transmission infrastructure such as substations. The IPT models
described below assume transmission assets that are connected with the country’s wider
electricity network rather than captive assets for the benefit of an
industrial offtaker (which are discussed in chapter 7. Other Private Funding Structures). Although an IPT is typically used for the development of greenfield
assets, we will also explore how the same concepts can be used for the
refurbishment of existing transmission assets.
In emerging markets, IPTs are implemented under a long-term contract,
generally between the state-owned transmission utility and a project company. The contract will typically define the
economic payment model, and the roles and responsibilities for the new
infrastructure, including ownership, construction, maintenance and
financing responsibilities. These contracts can be structured as transmission service agreements (TSA) but may also take other forms such as lease or line concession
agreements. In this chapter, the long-term contract will be referred to as a TSA although it
might have another name in practice.
IPTs have a proven record in many countries across the world including
Latin America and Asia. They are often described as a less disruptive
intervention in the transmission sector than the other available private
business models as they typically can be implemented with limited or no
regulatory reform. The IPT model, therefore, has the potential to unlock
many critical infrastructure projects in SSA and, if well structured,
could help African transmission utilities quickly finance lines that
have a direct and positive impact on their revenue.
IPT Business Models
There are a handful of different IPT business models which have
successfully resulted in transmission infrastructure built, maintained
and financed by private project companies. While very similar, in that
the private party assumes construction and financing risk in all IPT
models, they vary by degree of ownership and maintenance obligations
which will normally change the terms of repayment and the risk
allocation between the project company and the transmission utility. The
return on investment expectations, as well as the cost of financing,
will increase the more the project company bears risks that condition its repayment.
“Operations” — Line operation and maintenance or
system operation
“Operations” in this chapter refer to specific maintenance
activities required to ensure that a transmission line and other
associated infrastructure are available to be used when specified. This
is different from “System Operations'', which is carried
out by the transmission utility/transmission system operator (TSO) on a
whole network basis and involves system control and dispatch of
generation facilities. Notwithstanding the IPT model used, system
control and dispatch will be carried out by the transmission
utility/TSO, not the project company. Hence, in this chapter, operations
refer to “line operation & maintenance” only.
The TSA establishes the financial terms and period during which the
project company is entitled to receive payment in exchange for ensuring
the constructed transmission infrastructure is available to be operated
by the transmission utility as specified. In most cases, the project
company will not take demand risk (volume or price), or utilisation of transmission infrastructure risk, since the transmission utility will determine how, when, and by what means the grid is managed and
electricity is dispatched. The simplest way of structuring TSA payments
is as a fixed return on investment amortised over the term of the TSA,
structured as a service charge with scheduled payment dates. This type of annuity (or unitary payment) very clearly defines the
revenue stream by which investors and lenders can recover their
respective capital injections, which should lower lenders’ cost of
capital and investors’ return expectations. Also, when the transaction is structured appropriately, the
annuity payment becomes the key criterion for selecting the winning bidder,
assuming of course that competitive bidding is used.
The annuity payment will be sized to ensure the project company can
recover expenses associated with capital expenditure, financing and
operating and maintenance agreement (O&M) expenses related to
constructing, financing and, if applicable, operating the transmission
infrastructure. Depending on the IPT business model, there may be an
element of payment variability associated with asset performance linked
to O&M obligations. However, baseline payment will be sized to
ensure ongoing debt servicing. Below are the most common IPT business
models:
Build-Own-Operate (BOO): The TSA grants the project company the right to build and
maintain the transmission infrastructure for an undefined period.
Theoretically, the project company is not obligated to transfer its
ownership when the TSA terminates. This can cause issues around
ownership of the assets by the project company but no clear legal
basis for the revenue streams associated with it at the end of the
term. During the term of the TSA, a portion of the annuity
payment can be conditional on the project company meeting technical performance specifications or key performance
indicators (KPIs), ensuring the transmission infrastructure is
available to be fully utilised when required.
Build-Own-Operate-Transfer (BOOT): The TSA specifies that the project company has a
responsibility to maintain and operate the transmission infrastructure
for a period after the assets are constructed, before transferring
ownership and O&M obligations back to the transmission utility. As
with BOO, a portion of the annuity payment may be conditioned on the
transmission infrastructure meeting predefined KPIs.
Build-Own-Transfer (BOT): Once the assets are constructed, the TSA directs the project
company to transfer the ownership of assets to the transmission
utility upon project completion. O&M for the transmission
infrastructure may fall outside of the project company’s
responsibility and will most likely fall to the transmission utility.
In this case, the annuity payment will be unconditional on the transmission assets’ performance, because the project
company is not responsible for asset maintenance or operation.
In most IPT models that have been successfully implemented to date in
Latin America and Asia, the private ownership of transmission-related
assets is transferred to the transmission utility at the end of the TSA
term.
BOOTs used extensively in Latin America
38 projects implemented in Brazil (220kV lines for a total of 50,000 km) and 18 projects in Peru (220kV and 500kV lines for a total of 7,560 km) were BOOT.
Enabling Environment
There are some countries in SSA that have the regulatory environment or
experience with IPPs to be able to implement IPT business models within existing legislation. For
countries with a track record in IPPs, IPTs could be considered a
logical next step in using private capital to develop and expand their
electricity networks. Many of the same government stakeholders who
are familiar with the process and requirements of an IPP are likely to
have the capacity and relevant experience to enable IPTs, especially
when generation and transmission are bundled under the same
utility.
In many countries, a transmission licence will need to be granted to
the project company, either by a regulator or other relevant authority.
There may also be a legal prohibition on private companies owning
and operating transmission infrastructure (e.g., due to concerns about
the natural monopoly characteristic of transmission
infrastructure). If there are legal prohibitions, then there may be ways to structure
around this as described in the section below (Ownership of transmission
assets). If this is not possible, then an IPT business model can only be
implemented if the regulatory structure is amended to allow the granting
of a licence or appropriate authorisations by the regulator or relevant
authority.
A regulator will typically have a role in approving (and likely
licencing) the project company to implement a specified IPT business
model. Thereafter, the regulator is likely to be responsible for
monitoring compliance with licence conditions, which could include
identified KPIs under the TSA during the O&M phase. When the TSA
includes a simplified payment model, which eliminates demand risk, the
regulator will typically wish to understand and approve the payment
model. Before a TSA is being agreed to, the regulator needs to understand the cost
and benefit to the sector but will not need to review complex tariff methodologies
periodically during the TSA as required with power generation projects.
How It Works
Project phases
There are three key phases of an IPT project:
Project development
Construction and
Operations
Project development phase
See chapter 9. Planning and Project Preparation for a description of the planning process of transmission
projects. Project selection is critical in determining which
transmission infrastructure is suitable for an IPT. Some of the key
criteria to examine include:
The commercial case for the project
The economics of the relevant project will have to be analysed based on
the available data on the sector’s financial viability and growth
prospects, and a set of assumptions. Projects that deliver the following
efficiencies are well suited for an IPT business model: (i) can be
delivered faster with lower O&M costs by the private sector, and
(ii) likely to improve the sector’s cash flows by increasing the
network’s availability (e.g., by connecting new end users to power
supply, thereby meeting unserved demand). These types of projects are
generally identified during the power system planning phase.
The suitability of alternative funding sources
An analysis of whether there are other funds in the budget at the
national, ministerial, or utility level for the financing of the
infrastructure should be completed. The government should also assess whether there are
donor funds readily available to procure the project without it being an
IPT — if this is the case, some efficiencies from the private
sector’s ability to maintain and operate the asset at a lower cost
may be lost. If some alternative funding sources are identified, the
government should then decide whether the transmission infrastructure is
the best use of these funds.
The project size
An IPT is unlikely to be a suitable solution for smaller projects.
Typically, for projects less than US$50 million, given the expense
required for project preparation and execution, an IPT may not be the
most suitable method of financing. It should be noted, however, that
a series of smaller projects can be aggregated into a portfolio and executed as part of a
single IPT investment.
If there are any particular challenges associated with a particular project
An assessment of the overall legal and regulatory regime will be key to
identify any particular challenges with an identified project.
Environment and social risks should also be considered early to avoid
obstacles that might stifle the financing efforts at a later stage
(e.g., the construction of a transmission line through a protected
natural reserve). This is not to say that easy projects should be
implemented through the IPT model, but it would be wise that the first
IPT project does not have added complications, as implementing a
privately financed transmission project is challenging enough in a
country with no relevant experience.
The host country can decide to allocate a project to a developer at an
early stage in the project’s development or to undertake a certain
level of preparatory work first. Allowing the developer to take responsibility for early-stage
preparation provides more flexibility and may result in more innovation
and cost savings. It also relieves the government from raising funds for
project preparation and requires less capacity and government resources,
although external funding may be available for conducting feasibility
studies by the government or by the private sector. On the
negative side, the developer needs to be selected before the design and
investment requirements are finalised.
Countries can also choose to carry out a certain level of preparatory
work centrally before conducting an auction or tender process to attract
a greater level of investor interest and procure the most cost-effective
construction solution and lowest cost of financing. While effective,
this approach requires more resources initially to manage the project
preparation phase until the developer is selected. Further detail on
choosing between these approaches can be found in the Understanding Power Project Procurement handbook.
Regardless of who will be responsible for each activity, the following
workstreams need to be completed during the preparation stage:
Comprehensive feasibility study. A feasibility study will be required, which reaffirms the need for
the project, evaluates the alternative design options and recommends a
specific scope based on an economic analysis of the project and its
alternatives. The recommended scope along with the grid code (if
it exists) would form the basis for the design specifications.
Environmental and social impact assessment (ESIA). Environmental and social issues need to be identified as early as
possible in the project development phase. An ESIA will be required; they are usually conducted by third-party
environmental consultants. Even a preliminary ESIA could
identify major environmental and social issues which may have a
substantial impact on the project (affecting its design or routing or
even stopping the project). Early consultations with all the key
stakeholders are essential, including those concerning the potential
resettlement of peoples in areas along the transmission route.
Requirements by lending institutions may be relevant and need to
be taken into account.
Development of an EPC procurement strategy. How the project will ultimately be built and delivered will be
dependent on the strategy of the transmission utility and relevant
ministry. Assuming an IPT route is chosen, the IPT themselves
will have to choose how to procure the project, i.e. they will
typically run a process to choose an EPC contractor (or separate
suppliers of equipment and a contractor for civil works). This can be
a complex process due to issues of risk transfer and mitigation
between the transmission utility, project company, and construction contractors.
Permitting and licensing. There may be several permits and licenses that need to be obtained,
and it is important to lay out a plan as early as possible. Such
permits and licenses may include the following: land acquisition/lease, construction
permits (including access to the site), environmental permits, grid
connection agreements, operating permits, etc. If the country has a
grid code, it should be taken into account in both the design of the assets
and the required licenses/permits.
Developing a financing plan. This will be an early stage consideration and those developing
the project will keep improving it as the project moves forward, more
information becomes available, and risks are affected. Cost of
financing and key terms required by financiers will impact project
cost and delivery and this needs to be worked on iteratively with the
other development workstreams. See chapter 2. Financing Structures and Capital Sources for further details.
The development phase will end when the project reaches
“financial close,” i.e. when all conditions precedent to the
disbursement of the debt required for the project have been met, and
monies disbursed.
Construction phase
After a financial closure has been achieved, construction will begin.
The project company will typically be responsible for managing the project activities
required to complete the infrastructure, although in some instances
there may be a third party acting as construction manager. Even in the
case of a single contractor (EPC), an owner’s engineer will
typically be retained to supervise all aspects of the project and advise
the project developer/owner. Some financial institutions may
employ their own engineers and legal advisors to monitor construction,
in particular the environmental and social aspects. Lenders will
typically disburse their loans to fund the construction of the assets
during this phase, although in some cases the equity investor in the
project company may decide to finance the construction phase and
refinance once the asset is built and delivered.
Operations phase
Generally speaking in IPT models, the control and dispatch of power will be the responsibility of
the transmission utility acting as TSO, given the interface with the wider network.
It is possible, but rare, for the private sector project company
to take operational control of a section of the transmission network.
Maintenance of the asset, which may include some localised
operational activities, may be the responsibility of the project
company. The project company may decide to have its own staff or
hire a contractor to undertake this maintenance. In some cases,
maintenance will be the responsibility of the transmission utility, either under the terms of the TSA or because the project company
contracts back to the transmission utility under a maintenance agreement. The role of the project company in this
respect has an impact on investor risk and is likely to determine the
most suitable payment model that is agreed between the project company
and the transmission utility (or an alternative offtaker). The decision as to which party is
responsible for the maintenance and/or localised operations is a
function of the risk analysis and how the project fits into the overall
system strategy of the government.
Stakeholders
The roles of each relevant sector participant concerning an IPT are set out in the table below.
Sector Participant
Role
The project company will have at least one shareholder/equity sponsor.
In the case where projects are allocated earlier in the
process, the owner of the project company will probably also
develop the project. The developer will then either fund
the project company with sufficient equity to capitalise it in
the long term at a financial close or it will bring in a new
shareholder. As with the IPP sector, developers usually
carry out work and fund early-stage activities “on
risk” in consideration for earning development fees, which
are typically paid at financial close.
Among the other project development activities undertaken by
the developer/equity sponsor, it will take responsibility for
arranging debt finance for the project company. During the
lifetime of the IPT investment, the developer/equity sponsor
will manage the project company and be the key point of
interface between the project company and the
stakeholders.
Lenders will finance the project company with loans. They will
typically be mandated during the development phase to review the
contracts developed by the developer/equity investor and test
their “bankability” ahead of financial close (see below). At the financial close the lenders will fund
the project and their loans will be drawn down to fund
construction. IPT lenders include MDBs, bilateral DFIs, ECAs, and donor agencies. To provide long-term lending,
international commercial lenders will likely only be able to
participate with some kind of political risk or credit insurance
from an ECA or DFI. Some local funding may be available as part
of an overall funding package.
The “offtaker” is the organisation responsible for
paying the IPT under the Transmission Services Agreement.
In most cases, this will be the transmission utility, but it could be a different organisation in some countries,
such as a distribution company or another government
entity.
The transmission utility’s role in the sector is unlikely to change as a result of an IPT
project. In most cases, the transmission utility will continue to be responsible for all transmission
operations in the host country and it will control dispatch and
system operations. Existing infrastructure owned by the transmission utility will interface with the IPT’s infrastructure.
The terms of many IPT projects will involve the transfer of the
assets of the IPT project company to the transmission utility at the end of the term of the TSA.
The government’s role in an IPT project is typically to
assume certain state risks to protect the project company from
risks it is not best placed to manage. The agreement between the
government and the project company may be reflected in the
Government Service/Support Agreement (GSA), which needs to be
agreed upon and signed by both parties. The government here
could be one or more ministries (usually the Ministry of Finance
and the Ministry of Energy, or their equivalents) and may also
include a Ministry of Land. A PPP Unit or Presidential Delivery
Unit may also be a relevant governmental stakeholder.
The level of support provided by the government in this respect
will have an impact on the availability and pricing of debt and
equity finance available for the IPT project. See further
discussions in chapters 2. Financing Structures and Capital Sources and 11. Common Risks for further analysis on the range of government support
available during both construction and operations phases.
Contractual Structure
Figure 5.1: Relationship structure in an Independent Power Transmission
Special Purpose Vehicle model
Risk Allocation Matrix
The risk matrix below summarises how key risks might be allocated to
different stakeholders within a TSA. For a more detailed discussion and
commentary on the individual risks, especially as they pertain to
private investment in transmission infrastructure, please see chapter 11. Common Risks.
Please note that the table below is indicative and not meant to be
exhaustive. The precise risk allocation between the parties on any
particular transaction may be different to what is identified below as
typical. Risk allocation is always subject to the fact pattern
existing in relation to a particular transaction, investor appetite, and
what risks a government is prepared and able to take on with respect to a particular
transaction.
Risk
Stakeholder bearing risk
Govt/ Transmission utility
IPT project company
Financial risk
Demand risk
Credit risk
Inflation
Interest rates
Foreign exchange rates
Buy-out payment
Land
Pre-existing environmental conditions
Pre-existing conditions in the title
Land acquisition
Technical risk
Construction and commissioning of assets
Scope changes before or during construction
Interface between lines, substations, and generation
facilities
Technical risks related to the adoption of new technologies
Operation, maintenance, technical performance
KPIs, service levels
Accidents, damage, theft
Social and environmental risk
Social and environmental impacts
Occupational health and safety
Resettlement
Non-political force majeure events
Political and Regulatory Risks
Initial issuance of licenses, permits
Renewals, modifications
Changes in law
Changes in tax
Political force majeure events
Disputes
Resolution of disputes arising under contracts
Financing Structure
One of the main advantages that IPT business models bring is the ability for transmission utilities or
host governments to expand transmission infrastructure using
off-balance-sheet financing, via third-party investment and financing,
freeing up financial resources for other purposes.
Security Arrangements
It is important to note that while asset ownership may lie with the
project company for the duration of the TSA term, in practice, the key
form of security relied upon by project lenders will be the revenue
stream set out within the TSA. As indicated above, while a project
company may be entitled to own the transmission infrastructure which it
constructs permanently, the regulatory licensing regime or the TSA
itself may dictate that the ownership of transmission infrastructure be
transferred to the transmission utility at the end of the TSA term.
The TSA term is purposely defined for a long period (15 years plus) to
spread the cost of long term transmission assets across many years and
minimise the short term impact of servicing these payments on tariff
structures. Payments are likely to follow a regular schedule over the
term of the TSA.
Payment risk
As discussed earlier, simplified payment structures based on the
availability and performance of the transmission infrastructure strip
away demand risk based on utilisation (volume or end-user fees). This
has the benefit of clearly defining a predictable revenue stream which
represents a lower risk for investors and therefore attracts a lower
cost of capital. Any variability to the revenue stream introduced via
KPI metrics based on a split of risk allocation between the project
company and the transmission utility (e.g., for commissioning or O&M
responsibilities) may impact revenue risk but has the advantage of
ensuring service quality, which should improve the operating performance
and “availability” of the transmission infrastructure.
Payment risk mitigation
Whether additional credit support from a host government is required
will be a function of the credit of the entity responsible for making
scheduled payments. To the extent the paying entity, or offtaker, has a
healthy balance sheet or the payment obligation is irrevocable and can
be insured, there may be no need for a full sovereign guarantee to
backstop ongoing or termination support. Minimising any sovereign
contingent liability has the benefit of freeing up fiscal space.
If there are concerns about the offtaker’s ability to make timely
scheduled payments, the following can be pursued to provide liquidity
support:
government Support Arrangements including termination payments in
the event of non-payment under a TSA;
sector collection accounts that give a degree of priority in payment
waterfalls to investors;
establishing a bank account or a letter of credit structure that
maintains 6-month payment reserves; and
non-sovereign credit enhancement products. These are described in
more detail in chapter 2. Financing Structures and Capital Sources.
Advantages of IPT models
Although ECA support (typically for an EPC contractor) offers a host government
an off-balance sheet funding solution, the ECA still requires an
implicit guarantee by requiring the MoF to be a borrower for their
financing facility which can put pressure on the country’s debt
capacity. In addition, the ECA requirement that the borrower
provides a 15% contribution means there is still some amount of cash outlay expected
from public resources, usually in the form of a down payment. While
there could be alternative ways to finance the 15% contribution, this
will take additional time and resources to structure, which can result
in other inefficiencies.
While IPT financing may be more expensive than concessional loans or
ECA financing benefitting from an implicit sovereign guarantee, it can attract a more diverse set
of lenders and result in a lower cost for the project. As highlighted in the risk allocation matrix above, many types of lenders can provide cost-competitive financing to
support IPT business models. As outlined in the contract structure diagram in Figure 5.1, the borrower will be the project company that enters into
distinct construction and TSA contracts, and if applicable, an O&M
services agreement. Depending on the amount of financing to be raised,
the lender(s) can include MDBs, bilateral DFIs and ECAs who can provide
long-term loans. Commercial lenders may be able to provide longer tenor
loans with additional political and/or credit risk insurance from an ECA
or MDB.
Other Considerations
Aside from mitigating offtaker payment risk, there are a couple of other issues worth considering when choosing
to implement IPTs which deserve special mention: land
acquisition/right-of-way issues, and transmission infrastructure
ownership.
Land acquisition
Land acquisition is dealt with in chapter 10. Land Acquisition. To implement an IPT, the party that is best placed to manage this process
is best decided on a case-by-case basis. However, the experience from around the world suggests that land
acquisition/right-of-way risk, in most cases, is best handled by the
government or a public sector entity. Even countries with very
well-functioning power markets and numerous private transmission
projects already being implemented (such as Brazil) have the government
responsible for land acquisition.
In addition to ownership and local opposition, funding for acquiring
the land and compensating the various stakeholders may be an obstacle
too. Investors can play an important role, working with the
government, to ensure that adequate funding is available and the
compensation is fair and is done promptly. Land issues should be
resolved before the agreement with the private investor is
concluded.
Ownership of transmission
This section has focused on implementing IPT business models for
greenfield transmission infrastructure assets to raise financing that is
off the government’s balance sheet. As outlined when defining IPT
business models, the assumption is that the private sector will obtain a
licence to own the transmission infrastructure for some time, after
which the infrastructure is transferred to the transmission utility as
set out in the TSA. This could be for a period of e.g. 20 or 30 years
and is sized to allow the private sector developer to make a return on
its investment.
This follows the example of how PPP business models have been applied
to raise third-party financing to build other types of infrastructure,
especially power generation assets. It is rooted in the philosophy that
ownership of the asset runs concurrently with the project
company’s right and ability to operate the relevant asset.
It is typically also a lender requirement that the project company
owns the asset for the long term, so that in a scenario where the
project company has not been able to repay the debt it has incurred
(e.g., because the transmission utility has failed to make payments to
the IPT), lenders can recover their costs by selling the assets over
which they have taken security. Lenders will always take some form
of security (collateral) over the project company’s rights, title
and interests — and having security over assets
ensures that lenders have recourse to something of value, which they can
sell (or at least have the right to do so) if things have gone wrong and
the project is in default. Those rights are tied to the private
ownership of the assets themselves.
In transmission infrastructure projects, where the operation of the
relevant asset (e.g., the operation of a transmission line) may rest with
the government utility, the same logic of ownership may not necessarily
apply. In addition, unlike, for example, a generation asset such
as a power plant, dismantling hundreds of kilometres of transmission
infrastructure in a host country to sell to other parties (i.e., taking
the ultimate step to enforce security to repay the debt) is likely to be
less practical than for other types of assets. The analysis on ownership
will therefore depend on the relevant transmission assets in question,
who is operating it; and lender expectations. Security over revenue
accounts associated with the predictable revenue stream and any
credit-enhanced liquidity solutions and other contractual arrangements
are arguably where lenders should focus their attention when structuring
bankable solutions, rather than who owns the asset.
If this principle is accepted, there is room to argue that IPT business
models do not need to rely on private ownership, in which case the
refurbishment of existing transmission lines owned by the transmission
utility could raise third-party financing along the same fundamentals
outlined in previous sections of this chapter.
Case study — IPT: Peru
Peru is a country of 31 million people. Peak electricity demand
is around 6200 MW and electricity production is nearly 50/50 hydro and
thermal, even though renewables are increasing. 85% of the
installed capacity is linked to the national power grid (SEIN) and 15%
is in isolated systems. According to the World Bank in 2018,
the length of the transmission lines was approximately 22,600 km. The majority
of the demand is along the coast, as shown in Figure 5.2. Strengthening of the transmission capacity was a
priority in the late 1990s and early 2000s when many transmission
projects were implemented.
Reforms in the sector started in 1992, resulting in full deregulation
and substantial privatisation. Eventually, there were 70 power
generators, of which 65 rivately supplied 63% of the total energy.
There are 14 transmission companies, all private, and 23
distribution companies of which 13 are private with 67% market share.
Regulation of the power sector was well-designed and very
effective in supporting a well-functioning power market.
Procurement of privately financed transmission projects started in
1998. The PPP process provided the framework for procuring
transmission projects. Early on, it was decided that a BOOT model
would be used and private investors would be selected through a
competitive process. A well-balanced risk allocation matrix (among
the investor, offtaker and government) provided the basis for de-risking
these projects, leading to very competitive tariffs and substantial
savings, as shown in Figure 5.3. The basis for bidding was an annuity, independent of demand and
utilisation of the assets.
Eighteen tenders have now been completed leading to the implementation of a
total of 7,560 km transmission lines (220kV and 500kV) and a total
budget of $2.6 billion. All these projects were based on a BOOT
model and were 30-year contracts.
Figure 5.2: Peru transmission lines (Source: Pedro E. Sanchez, World Bank 2018)
An important conclusion that can be drawn from the Peruvian experience is that
privately financed projects have been implemented at a fraction of the
expected cost. The experience in other countries (e.g., Brazil and
India) were similar. As an illustration of this, Figure 5.3 below shows that the winning bids in Peru provide significant
savings to the electricity sector versus projected costs (an average of
36% lower).
Figure 5.3: Peru — Private Transmission Projects implemented in the period
1998-2017 (based on data in Pedro E. Sanchez, World Bank 2018)
A case needs to be made on a project-by-project basis as to whether the
benefits of an IPT in terms of availability of funding, flexibility
of funding, and risk transfer to the private sector, mean that this is
the most appropriate solution. The risks that the project company agrees
to take will, to a large extent, determine the returns required by
investors. An IPT will not always be the best solution and most
countries will likely have a long list of projects that are more
suitably funded with support from public funding sources.
However, experience in many countries demonstrates that when well
structured and applied to the most appropriate projects, IPTs can create
substantial value for the sector, improve the quality of power and
enhance energy access. They can lead to efficiencies and lower costs for
tariff payers.
Strategically, a host country’s decision to involve the private
sector in the transmission subsector is a sensible way to improve power
sector efficiency and reduce power supply costs. However, a
necessary supplement to privately financed transmission should be a
roadmap to power sector financial sustainability. IPTs can play an
important role in making power sectors more efficient by unlocking
critical projects that increase network ability to deliver power to
areas of unmet demand and therefore increase sector cash flows. If
correctly structured, they can also bring very material efficiencies, as
illustrated by the experience of Peru described above.
Summary of Key Points
Independent power transmission projects (IPTs) involve the design, construction, and financing of a single
transmission line or a set of transmission lines and associated
infrastructure such as substations.
IPTs are implemented under a long-term contract, generally between
the state-owned transmission utility and a project company. The
contract will typically define the economic payment model, and the
roles and responsibilities concerning the new infrastructure,
including ownership, construction, maintenance and financing
responsibilities. These contracts can be structured as transmission service agreements (TSA) but may also take other forms, such as lease or line concession
agreements.
Thousands of kilometres of IPTs have been developed in Latin America,
India, and elsewhere. An important conclusion that can be drawn
from the experiences of Brazil, Peru, India, and other countries is
that IPTs are often implemented at a fraction of the anticipated cost.
In Peru, for example, IPTs cost 36% less than expected on
average.
Governments will consider a whole-of-grid concession when there is the
expectation that a concessionaire can (1) better maintain and operate the existing transmission network to improve
the overall availability and ultimately utilisation of transmission
infrastructure and (2) invest in extending/upgrading the network to improve
reliability and access to the power supply.
A whole-of-grid concession extends the right to develop, construct,
operate, and maintain transmission infrastructure (the “concession”) to a private sector concessionaire, who in turn receives
remuneration for the concession period. A concession can be a grant of
rights or property, depending on the jurisdiction. Transmission assets
are either leased or sold by a government or transmission utility to a
private sector concessionaire to take over the role of the transmission
utility via a concession agreement, a lease and assignment agreement, or a similar agreement.
Regardless of the contract form, the concessionaire may have to pay an upfront investment for the rights to maintain and operate the transmission
infrastructure, although this is not always the case. The concessionaire
would typically be compensated via payments it collects from its
customers (generators, distribution companies, or industrial consumers
that are directly connected to the transmission system).
The upfront payment owed by the concessionaire, and the form of this
payment, is covered in further detail later in the chapter. The amount the concessionaire is required to earn in a year to cover
its costs and earn a return on its investments (the annual revenue requirement) is calculated using performance-based rate making or cost of service regulation. In
either ratemaking method, the revenue requirement is based on the
regulated asset base (RAB) or rate base — a measure of the value
of the assets which are used to perform a regulated service. In a whole-of-grid concession, the RAB would include all transmission infrastructure the concessionaire is expected to maintain,
operate or expand to deliver services to a defined customer base (e.g.,
generators, bulk distributors, large industrial customers, etc.) in a
defined geographic area. In exchange for delivering these services, the
concessionaire earns and collects fees directly from those
customers.
In principle, this methodology assumes that customers are paying a
cost-reflective tariff that will ensure full recovery of the
concessionaire’s investment in transmission assets, reducing the
investor’s risk of investing in capital-intensive projects. If
regulated tariffs are below what the concessionaire requires to recover
its costs, then the transmission utility or other government entity will
be required to compensate the concessionaire some other way. This is covered in greater detail later in the chapter.
Concession Models
There are two main ways a whole-of-grid concession may be
structured:
concession for the whole existing transmission network; and
concession of a portion of an existing transmission network, which
can be limited to a territorial area or identified transmission lines
and related infrastructure.
The concessionaire, via a project company, is typically responsible
for:
the operation and maintenance of the transmission
infrastructure;
refurbishments, restoration and repairs to existing transmission
assets;
construction of new transmission infrastructure, upgrades, and
expansions within the concession area;
all investments required for the stable and efficient operation of
the transmission infrastructure; and
operational control of the transmission network within the concession area.
The rights conferred to the concessionaire must allow it to exert
sufficient and unfettered control to manage its transmission network
responsibilities without government or transmission utility
interference. The government’s role is limited to an oversight
role — i.e., an independent regulator that oversees tariff
methodology and a planning role — set out in the concession
itself. This “concession” right, depending on the
jurisdiction (and asset), could be a grant of rights, land or property,
or a combination of all three. However, title to the relevant land and
properties may not always pass to the concessionaire as a result of the
concession. What is more important is that the concessionaire retains
the rights to control, maintain and operate the relevant asset —
in this case, the entire national grid — and that these rights are
granted in a manner that is legally valid, binding and enforceable
(including with parliamentary or cabinet-level approval, where
necessary).
In all cases, the transmission assets are transferred back to the
transmission utility at the end of the concession.
Enabling environment
Whole-of-grid concessions are suitable in jurisdictions that have an
independent electricity regulator and have a regulatory framework that
allows for third parties (such as a concessionaire) to hold a
transmission licence that permits them to construct, operate and
maintain transmission infrastructure. It is also important that the
legislative framework permits private sector parties to own or operate strategic transmission assets. Changes
to legislative and regulatory frameworks to permit whole-of-grid
concessions where the existing regulatory regime does not permit
investors to be concessionaires can be a complex, expensive, and
time-consuming undertaking.
The allocation of risks in a whole-of-grid concession also plays a
significant role in determining the success or failure of efforts to
structure and award a concession. This is discussed in further detail
later in the chapter.
Tariff considerations
Considering the ongoing investment required in the operation and
maintenance of transmission infrastructure, it is not practical to
establish a tariff from the outset that the concessionaire may charge
customers for use of the transmission service for the entire term of the
concession. To avoid renegotiating, restructuring, or early termination
of a concession due to an insufficient or inadequate tariff, the tariff
methodology the regulator intends to use should be clearly articulated
in a set of tariff guidelines or the concession agreement. The two most
common forms of regulation on which tariff methodologies are based are
the cost-of-service approach and performance-based regulation. While these will not be covered in detail in this book, each has its
advantages and disadvantages which need to be carefully considered.
The important principle is that the concessionaire’s annual
revenue requirement should be sufficient to allow for a return on the
RAB equal to the amount of the RAB times the weighted average cost of
capital, operating and maintenance costs, taxes, and depreciation of
existing assets.
The soundness and certainty of the RAB valuation and associated tariff
methodology are critical to the success of implementing a whole-of-grid
concession, given that the tariffs charged to customers for their use of the
transmission infrastructure are the main source of revenue (and in some instances the only source
of revenue) to the concessionaire.
A concessionaire’s revenue shortfall may sometimes be as a result
of its failure to meet certain KPI set by the
regulator. In this case, the government or the transmission utility
would not be required to cover such a shortfall. However, if the
shortfall is a result of the regulator’s failure to apply
appropriate tariff guidelines, the government or the transmission
utility will need to find an alternative way to compensate the
concessionaire or face a potential termination of the concession. The
compensation may take the form of a one-time payment or an ongoing
subsidy to the concessionaire.
If there is a material unfavourable future change in the tariff
methodology that does not adhere to the principles of full cost recovery
plus a return on investment, this would be detrimental to the financial
viability of the concessionaire. The government support agreement (discussed in further detail below)
would typically address this risk.
In countries that do not have an established independent regulator,
economic regulation can still be achieved through a government support
agreement or concession agreement which includes an annexe that
describes a regulatory methodology. The government support agreement (between the host country and the
concessionaire) or the concession agreement (between the transmission
utility and the concessionaire) will then govern the relationship
between the asset owner and the service provider, and the relevant
government counterparty will be responsible for monitoring the
performance of the operator and for applying the regulatory methodology
following the terms of the contract. This system is known as
“Regulation by Contract.”
Case Study — Transmission Concession: Philippines
Source: Private Sector Participation in Electricity Transmission and
Distribution/ Experiences from Brazil, Peru, The Philippines, and Turkey
(World Bank, 2015), pages 6-9.
The Philippines is an example of a long-term (25-year) concession for
existing transmission assets. The main goal was to raise
capital for the sector and the Treasury. This goal was eventually
satisfied even though it took longer than initially expected;
privatisation of the transmission system attracted close to $4.2 billion
in a concession deal that closed in 2007.
Initially (2001), the regulatory framework was established under a
comprehensive restructuring and privatisation programme, known as the
Electric Power Industry Reform Act (EPIRA). At the same time, the
energy regulatory commission (ERC) was created. Performance-based
regulation (PBR) formed the basic framework and a specific methodology
for regulating the revenues of the transmission company was developed.
A "revenue cap" approach was adopted for the
transmission company.
While the essential regulatory elements were in place since 2003, it
took a few years for the ERC to improve the rate-making methodology and
impose the necessary discipline for setting the specific revenue cap
levels. As a result, there were two unsuccessful attempts before the
third successful one in December 2007. Bidders were very
interested to invest in the Philippines mainly because of the following
three factors: (1) there was promising growth prospect in the economy and
the power sector; (2) there was a clear and steadily improving regulatory
framework; and, (3) there was a vibrant domestic private sector which was
interested to participate.
Eventually (in 2007), there were a sufficient number of eligible
bidders, who were convinced of the quality of the regulatory framework
and the integrity of the competitive process. The National Grid
Corporation of Philippines (NGCP), a corporate vehicle of a group of
local and international companies, won the concession.
Predictable Transmission Tariffs Set the Stage for Transmission Company
Concession in the Philippines
“The efforts to attract investors to the Philippine transmission
business were an essential part of the government's electricity
reform programme stipulated under EPIRA in 2001. However, the efforts to
complete the required auctions failed twice in 2003, and then again in
February 2007. Regulatory uncertainty about the transmission
company's revenue streams was the main concern voiced by investors,
even though the transmission company had published the first set of
essential guidelines on the subject. The failure of the first two bids
can be attributed to the short track record of ERC and its PBR
methodology. An additional source of uncertainty for bidders was the
relatively short (three-year) duration of the first regulatory period
set by the tariff guidelines. The period would end on December 31, 2005,
after which the rates would be subject to revision.
For the second (2006-2010) and third (2011-2015) regulatory periods,
the revenue cap methodology still applied. However, the regulatory
uncertainty remained high in 2006, as the specific revenue cap levels
were still debated. The continued uncertainty undermined the
bidders' confidence, and the government finally decided to drop the
third tender in February 2007 when only one bidder remained. At this
point, the government preferred to announce a new auction rather than
negotiate directly with the sole remaining bidder. The ERC used the
opportunity to better prepare for the next auction. The regulatory asset
base (RAB), a key component in the estimation of the maximum allowable
revenue, was established and could be used by investors in preparing
their bids. This set the tone for transparency and predictability of
ERC's regulatory process.
The payment of the initial concession fee
was made easier by requiring an upfront payment of only 25 per cent and
the deferred payment of the balance under precise terms and conditions
set before the final bid. In the new auction in December 2007, the
successful bid by NGCP yielded $3.95 billion, well above the RAB level
that was set around $3.0 to 3.2 billion.” (World Bank, 2015, p. 8)
Figure 6.1: Milestones in the Transmission Company Concession in the
Philippines (Source: Private Sector Participation in Electricity
Transmission and Distribution/ Experiences from Brazil, Peru, The
Philippines, and Turkey (World Bank, 2015), p. 8)
How It Works
Procuring a whole-of-grid concession
Host countries that seek to implement a whole-of-grid concession may
procure them (1) by conducting an international competitive tender or
(2) through direct negotiations. In both cases, the process would
likely be subject to laws governing the procurement and/or
public-private partnerships. MDBs and donors providing concessional financing often find it easier
to support infrastructure projects that have been procured following a
competitive tender process.
In a competitive tender, the qualification and evaluation criteria of
the tender determine the selection of a concessionaire. Where a concession fee is required to be paid either upfront or
periodically over the term of the concession agreement, the price
offered for the concession fee will likely be a significant
consideration in the award of the concession as well as the concessionaire’s return expectations.
The implementation of a concession will impact the process of planning
the development of the transmission system. Given the duration of a
whole-of-grid concession and the concessionaire’s role in
investing in network expansion, the concessionaire will likely become a
key stakeholder in system planning. Under traditional cost of service regulation, a concessionaire
may have a strong desire to obtain some form of commitment from a
regulator that the regulator will include the capital costs associated
with a future project in the rate base when the project is placed into
service. Under performance-based rate-making, a concessionaire may be
required to submit periodic business plans to the regulator which outline the new projects it intends to undertake. Those business
plans are in turn used to establish the annual revenue requirements for the period that is covered by the business plan.
Concession fees
A concession agreement typically provides that the concessionaire will
pay upfront or ongoing concession fees to the transmission utility. A
concession fee provides a source of revenue to the transmission utility
which it can use to fund its ongoing costs. A balance must be struck
between how much the transmission utility needs to recover against the
impact on transmission fees to the system: generally, higher concession
fees will lead to higher transmission charges.
At the same time, it is important to recognise that the transmission
utility may have ongoing liabilities which may not have been transferred
to the concessionaire, for example, servicing a pre-existing debt. The
transmission utility would need to earn revenues that are sufficient to
enable it to pay for these liabilities as they come due. There may also
be ongoing costs incurred by the transmission utility throughout the
concession period, including administrative overhead to enable it to
administer the concession agreement, maintain its ownership interest in
the transmission system, and servicing debt repayment obligations.
There are different options that a transmission utility may choose to
charge a concession fee to a concessionaire to extinguish or meet its
ongoing liabilities, which are discussed in the Table 6.1.
Option
Description
Option 1
Under this option the concession fee would consist of:
An up-front payment calculated as the value of the RAB (or a
significant portion thereof); and
Ongoing payments that are sized to enable the transmission
utility to cover its ongoing costs during the term of the
concession.
The transmission utility would use the up-front payment to
retire its debts and would use ongoing payments to fund the
ongoing expenses for the term of the concession.
The regulated asset base of the concession would initially be
established as the amount of the up-front payment. That portion
of the regulated asset base would depreciate at a specified rate
designed to balance the competing interests of reducing the
regulated asset base and reducing the depreciation charge
recognised in each annual revenue requirement.
Option 2
The concessionaire does not pay an upfront concession fee because the transmission utility retains its RAB, which would continue
to depreciate following the regulatory concepts discussed in
Option 1.
The concessionaire will continue to collect revenue from the
customer base, and remit via the concession fee that portion
owed to the transmission utility to cover its debt obligations
and ongoing administrative overheads.
The concessionaire will start to earn a return on new
investments made (including depreciation) for capital
expenditure investments in upgrades or greenfield transmission
network extensions.
Option 3
The concessionaire does not pay an up-front concession fee to
the transmission utility. The ongoing concession fee paid to the
transmission utility will be sized to cover two distinct
components:
A component sized and sculpted to enable the transmission
utility to pay its debts as they become due; and
A component sized to enable the transmission utility to cover
its ongoing costs during the term of the concession.
Table 6.1: Options for establishing a concession fee
Any number of permutations of these three options could be used to set
the concession fee in a manner that aligns with the priorities of the
host country and the ability of the concessionaire to raise debt and
equity to fund any up-front and ongoing payment obligations. Option 1
would result in the highest upfront payment to the transmission utility
(which would likely be paid to the government as a special dividend).
In most cases, it would also result in higher use of system fees
and therefore higher rates for consumers. Option 3 may, depending
on how the debts of the transmission utility are structured, result in
the lowest use of system fees and therefore the lowest rates for
consumers. Option 2 can be tailored to achieve the desired blend
of those two outcomes. Which option a government should pursue
depends on its objectives.
Stakeholders
Identifying and mapping stakeholders and their likely interests,
concerns and objectives is an essential first step in determining groups
of stakeholders that may support or oppose a whole-of-grid concession,
with proper stakeholder engagement. To ensure successful implementation,
it is important for the team responsible for structuring the concession
to consider reasonable concerns and objectives of all affected
stakeholders. These stakeholders include the host government (notably the ministries
responsible for finance and electricity), the regulator, the
transmission utility, generators, distribution companies, and consumers,
along with potential lenders who have extended loans to the transmission
utility. The most significant effects on those participants are mapped
in the matrix that follows in Table 6.2.
Sector Participant
Role
The ministries involved in financing and executing new
transmission implementation will now need to pay for and
administer any subsidies, if required, to make the
concessionaire whole. They will need to plan to raise the
termination payment/ “buyout price” at the end of
the term or upon the earlier termination of the
concession.
Regulators in SSA generally have significant experience
regulating publicly-owned utilities, but limited experience
regulating privately-owned utilities. A higher degree of
oversight is required for privately-owned concessionaires,
including regulatory methodology and KPIs,
to ensure fairness and transparency. As private sector
participation is introduced, both the independence of the
regulator and the technical proficiency of the regulator become
more important.
The transmission utility will primarily be responsible for
administering the concession agreement, maintaining its
ownership interest in the transmission system, and servicing
liabilities it retains.
The concessionaire may be required to hire substantially all of
the transmission utility’s employees as a concession
condition. In all cases, employment considerations would also be
influenced by local law requirements, impacting costs.
Connection agreements and TSAs between generators, distribution
companies, and industrial customers and the transmission utility
will need to be transferred to the concessionaire. Consideration
will be required regarding impact to generators, distribution
companies, and industrial users, including liability for grid
interruption and unavailability.
If the transmission utility performs the role of a single-buyer
and has entered into power purchase agreements in respect of
independent power projects, those agreements should be reviewed
to determine whether the implementation of the concession will
trigger any defaults under existing PPAs.
Development finance institutions that fund, or may be
interested in funding, the development of new transmission
infrastructure will be interested in exploring how they can
continue to fund the development of new transmission
infrastructure after the concession has been implemented.
Table 6.2: The potential effects of the whole grid concession model on sector actors
Contractual Structure
The participants in a concession and their contractual relationships
are shown in Figure 6.2. The structure presented in Figure 6.2 assumes that the state-owned
transmission utility does not act as a single buyer. If the state owned transmission utility
does act as a single buyer then additional contracts will be necessary to separate rights and
obligations related to transmission from rights and obligations related to supply.
Figure 6.2: A typical concession structure.
As the concessionaire constructs and installs new equipment and
facilities and those facilities become part of the transmission system,
legal title to the new equipment and facilities vests in the
transmission utility so that the transmission utility remains the owner
of the entire transmission system during the term of the concession. If,
for example, the concessionaire needs to acquire additional
rights-of-way, easements, ownership interests, or leasehold interests in
land to expand the transmission system, the concession acquires those
interests in the name of the transmission utility, and those interests
become subject to the leasehold interest and access rights created by
the concession without further action by the concessionaire or the
transmission utility.
The concessionaire will be responsible for operating and maintaining
the transmission system. If the legislative framework provides that the
holder of a transmission license is responsible for dispatching
generation and balancing the system, then the concessionaire will be
responsible for those functions. If the legislative framework
contemplates that those functions will be performed by a transmission
system operator, then those functions will be performed by the entity
that holds the license to act as the transmission system operator.
Although the concessionaire may also hold the license to act as a
transmission system operator, a different entity will perform those
functions in markets that separate the transmission ownership and
transmission system operator functions.
The concessionaire will recover its ongoing operations and maintenance
costs from the use of system fees it charges for transmission. It will
finance capital expenditures to upgrade and expand the transmission
system with a combination of debt and equity. Equity will be contributed
by the shareholders in the concessionaire or created by the retention of
earnings by the concessionaire. The concessionaire will raise debt by
borrowing from lenders or by issuing bonds or preferred shares. The
concessionaire’s ability to raise capital in the form of equity,
debt, and preferred shares is highly dependent on how the concessionaire
is regulated.
Key project agreements
In a typical whole-of-grid transmission concession, a state-owned utility that owns a transmission
system (the “transmission company” or the “transmission utility”) grants a concession over all or a portion of its transmission
network to the project company established to act as the holder of the
concession (the “concessionaire”). At the same time, the ministry that is responsible for
overseeing the electricity sector or the Independent Regulator that regulates the electricity sector, if one has been
established, typically grants a transmission license to the
concessionaire. In addition, the host country may enter into a
government support agreement, implementation agreement, or similar
agreement (a “government support agreement”)with the concessionaire to provide certain identified types of support
to the transaction. We explore these three key documents below. We also
take a look at a key concept for the financing of whole-of-grid
concessions, and termination payments, below.
Concession agreement
The concession agreement will typically provide that:
The transmission utility will retain ownership of the existing
transmission system but will concede and/or lease the existing
transmission system and related immovable assets that are useful for
operating and maintaining the network and are used by the transmission
utility for that purpose to the concessionaire for the life of the
concession.
The transmission utility will lease or sell to the concessionaire all of the transmission utility’s moveable property, equipment, and
inventory of spare parts.
The transmission utility will transfer its right, title, and interest
in some contracts to which the transmission utility is a party, which
may include ongoing service contracts, contracts for the supply of
goods and equipment, and contracts for the construction or supply of
new assets that will become a part of the transmission system.
The concessionaire will pay a concession fee, which may be structured as a one-time payment,
ongoing payments, or a combination thereof, in exchange for the
concession rights that have been granted to it.
The concessionaire will use the leased or transferred assets to provide
transmission services within the host country (or part of it) as
described in the transmission license.
The concessionaire will improve, repair, operate and maintain the
transmission system, and
The concessionaire will expand, reinforce, and upgrade the
transmission system to the extent required to provide transmission
service within the relevant host country, and to the extent that
expansion projects are approved by the regulator per the tariff
guidelines.
Government support agreement
As far as a whole-of-grid concession is concerned, government support
agreements will cover similar risks as in IPTs — although they may have additional and specific protections
relating to any outstanding risks that fall to the government concerning
an entire transmission system including, for example, pre-existing liabilities that relate to the transmission system assets before they are handed over under the concession.
Termination payments
The concession agreement and/or the relevant government support
agreement will include a termination payment or “buy-out
price”, which is payable at the end of the term of a concession
or earlier, upon certain early termination events.
This payment amount, if paid at the end of a concession, may often be
set to equal the regulated asset base as of the end of the last year of
the concession. In scenarios other than the expiration of the term, the termination payment could be calculated by applying a multiplier to
the regulated asset base.
In the case of early termination of the concession following (i) an
event of default by the state-owned transmission utility under the
concession agreement, (ii) an event of default by the host country under
the government support agreement, or (iii) the occurrence of a prolonged
political force majeure event, the multiplier may be greater than 1 in
order to provide an incentive for the host country and the transmission utility to perform
their obligations under the project agreements. Similarly, in the case of early termination of the concession
following an event of default by the concessionaire, the multiplier may
be less than 1 in order to provide an incentive for the concessionaire
to perform its obligations under the project agreements. The
incentives created by a multiplier other than 1 should not be viewed as,
or sized in terms of, a penalty, which could be unenforceable under the
laws of many host countries.
Termination payments can be sizeable, as the amount of the termination
payment is directly correlated with the amount of investments made by
the concessionaire during the term of the concession. On the other hand,
a host government may find that a concessionaire has performed well
over the term of the concession and that there is little rationale for
allowing a concession to expire. A concession agreement and government
support agreement may contemplate that the host government, the
transmission utility, and the concessionaire may agree to extend the
term of the concession before its expiration.
Transmission licence
The concession agreement and Government Support Agreement may contain
only a part of the obligations of the concessionaire. Other obligations
the concessionaire will need to perform are likely to be set out in the
wider legislative framework, including any implementing regulations
issued under the regulatory framework, and any licences issued to the
concessionaire by the regulator.
Some of the issues the licence may address particular to a concession include:
The geographic service territory over which the concessionaire will
be responsible for transmitting electricity and the nature and scope
of any exceptions to the concessionaire’s exclusive right to
own, lease, construct, or operate a transmission system within the
service territory.
The term of the licence (which should be aligned with the term of the
concession).
The KPI that apply to the concessionaire and
the amount of any fines the regulator may levy in the event the
concessionaire does not meet the KPI.
The scope of the concessionaire’s obligation to expand the
transmission system.
If the concessionaire will perform the role of a transmission system
operator, any obligations that are specific to that role, such as an
obligation to comply with a grid code or dispatch code.
Any transition provisions, which might include an agreement by the
regulator to forbear enforcing KPI during a
limited and defined period at the beginning of the term if the
transmission utility has not been able to consistently meet or exceed
the key performance indicators.
These obligations will need to be aligned with the concession agreement
(or conversely, the concession agreement needs to be aligned with the
requirements of the licence). The rights and obligations that are set
out in the transmission licence will impact the risk assessment of
potential investors in the concession, the bankability of the
transaction, and the service levels consumers should expect of the
concessionaire.
Risk Allocation Matrix
Many of the risks that arise in the context of a concession are
described and discussed above. Please note that the facts and
circumstances surrounding a particular whole-of-grid concession will
impact how risks are allocated. The risk matrix below summarises how key
risks might be allocated to different stakeholders within a concession
agreement. For a more detailed discussion and commentary on the
individual risks, especially as they pertain to private investment in
transmission infrastructure, please see chapter 11. Common Risks.
Please note that the table below is indicative, and not meant to be
exhaustive. The precise risk allocation between the parties on any
particular transaction can vary from what is presented below. Risk
allocation is always subject to the fact pattern existing with a
particular transaction, investor appetite, and what risks a government
is prepared and able to support on a particular transaction.
Risk
Stakeholder bearing risk
Govt/Transmission utility
Concessionaire
Consumers
Financial risk
Demand risk
Credit risk
Inflation
Interest rates
Foreign exchange rates
Termination payment
Land
Pre-existing environmental conditions
Pre-existing defects in title
Land acquisition for expansions
Technical risk
Construction and commissioning of new assets
Scope changes before/during construction
Interface between transmission infrastructure and generation facilities
Technical risks related to technology risk
Operation, maintenance, technical performance
KPIs, service levels
Accidents, damage, theft
Social and environmental risk
Social and environmental impacts
Occupational health and safety
Resettlement
Non-political force majeure events
Political and regulatory risk
Initial issuance of licenses, permits
Renewals, modifications
Changes in law
Changes in tax
Political force majeure events
Disputes
Resolution of disputes (contractual)
Resolution of disputes (tariff methodology)
Financing a Whole-of-grid Concession
Financing models for whole-of-grid concessions
Network industries require ongoing investment. Ongoing investment
requires ongoing increases to the equity invested in the business and
ongoing increases (and repayments) of debt. Project finance
structures are not well suited to ongoing and open-ended borrowing.
For this reason, network utilities with ongoing investment
requirements are, as a general rule, financed using corporate finance,
not project finance. This has several implications. For
example:
the range of debt-to-equity ratios that can reasonably be achieved
using corporate finance is lower than the range of debt-to-equity
ratios that can be achieved using project finance;
the tenor of corporate loans are significantly shorter than the tenor
of project finance loans;
unless a corporate borrower issues bonds, the interest rates on its
debt obligations are, as a general rule, floating rates; and
corporate borrowers have a constant need to borrow to roll over their
debt obligations.
Given these implications, large utilities have active borrowing
programmes that may result in the issuance of multiple series of bonds
and multiple borrowings under lines of credit or fixed-term loans during
each year. This should not be surprising, given that project
financing techniques were developed in part to increase debt-to-equity
ratios, increase tenors, and enable borrowers to hedge their exposure to
floating interest rates.
Viability gap funding
A significant portion of greenfield transmission infrastructure has
been financed by donors and concessional financing from MDBs.
A whole-of-grid concession does not preclude donors and MDBs from still
financing new transmission infrastructure build, nor does it change the
role of DFI or ECA lending for new transmission assets. Transmission
assets that continue to benefit from donors or other external financings
can still be operated by the concessionaire.
Donor funding can also provide viability gap funding to help support a
concessionaire’s acquisition of a regulated asset base, with the
remainder of the funding being financed by the concessionaire. The
concessionaire would earn a return on the portion of the asset base it
has self-financed, but not a return on the donor portion of the
financing. The blending of donor or concessional capital in this way
helps subsidise the cost to the concessionaire of operating and
maintaining sections of the transmission network which may be less
commercial or in a poor state.
Other Considerations
This chapter has discussed the whole-of-grid concession in the context
of concessioning the operation, maintenance, and expansion of the
transmission network on a standalone basis. In reality in Sub-Saharan
Africa, there are only a handful of examples where the transmission
network has been concessioned, and generally, this has been the case
when it has been bundled along with generation and distribution
services. At the time of writing, there are no whole-of-grid private
sector concessions in the transmission sector operating in the African
continent, although globally there are multiple examples, including in
the Philippines and parts of Latin America.
If power generation, transmission, system operator and distribution
remain the responsibility of vertically integrated power utilities, as
is the case in many African countries, whole-of-grid concessions in the
transmission space may only follow once the sector has been unbundled,
or if the entire energy sector is the subject of a concession. This has
been the case, in Cameroon, between 2000 and 2015 with AES-Sonel.
In countries where generation, transmission, and distribution are
unbundled, system operators are still challenged in their ability to
charge cost-reflective tariffs to end users required to enable upstream,
midstream and downstream activities in the energy value chain to recover
their costs. This is an argument for granting concessions concerning
“bundled” assets — so that the generation tariffs can
cross-subsidise those on the transmission side, for example.
However, incentivising the private sector by enabling them to be able
to charge end users to recover the costs required to build, own and
operate entire energy systems is not straightforward given the high
capital costs involved and challenges in recovering costs from end users
which then do not prohibit access to the electricity.
As a host country considers whether a whole-of-grid concession is an
appropriate approach for helping to finance new and existing
transmission infrastructure capital expenditure, it should consider (i)
how its energy sector is structured, (ii) the role of electricity sector
stakeholders and how their responsibilities may be impacted, and (iii)
how to engage existing stakeholders to build support for the successful
implementation of this approach.
A whole-of-grid concession may be appropriate if a host country desires
to:
leverage the experience and know-how of the private sector to improve
the technical and commercial performance of a transmission
utility;
relieve budgetary constraints by transferring the responsibility for
financing capital expenses to the private sector for the development
and construction of the projects that are required to expand,
reinforce, and upgrade the transmission system; and
retain long term ownership over the transmission system.
A whole-of-grid concession may be less attractive to a host country
that:
has an existing transmission utility network whose performance equals
or exceeds international performance benchmarks; and
is targeting financing for a discrete or a package of transmission
infrastructure assets that might be more efficiently financed via IPT
Summary of Key Points
A whole-of-grid concession grants a private party the right to
develop, construct, operate, and maintain transmission infrastructure
in a defined geographic area, which is usually but not always an
entire country.
A whole-of-grid concession may be appropriate where the government
expects that a concessionaire can: (i) better maintain and operate the existing
transmission network, and (ii) raise the capital needed to finance extensions and upgrades to the
network.
The private concessionaire derives their revenue from charging of
transmission use of system fees to generators, distribution companies,
and industrial users with a direct connection to the transmission
system.
The fees charged by a private concessionaire are usually established
by an independent regulator pursuant to a set of tariff guidelines or
a tariff methodology that is developed specifically for the
concession.
In this chapter, we describe other private sector-led models of
procurement for transmission infrastructure, namely:
merchant transmission lines
industrial demand-driven model, and
privatisations
These models are described to ensure that the spectrum of private
participation options is covered by the book, although the authors
believe that these models are less likely to be adopted or
operationalised in the near term in the African context given other
priorities of the sector. Nonetheless, it is conceivable that they form
part of the future transmission infrastructure story in the African
continent.
Merchant Transmission Line
A merchant transmission line consists of one or more lines that connect
existing transmission grids/power markets or consumers that were
previously isolated. Such transmission lines are entirely private in the
sense that ownership, control, financing, construction, operation,
maintenance, and tariff setting of the lines rests entirely with the
private developer. Access to the merchant line is at the discretion of
the owner. Therefore, it is not open to all transmission users.
Traditionally, merchant lines were developed by independent companies
seeking to use the system to wheel power between markets where there is
a difference in electricity prices. Trading power from lower-priced
markets into higher-priced markets allows the company to profit from
pricing arbitrage. This model of financing is a market-driven model to
provide transmission infrastructure that supports competitive wholesale
markets for electricity. However, this model may not be viable for
markets where tariffs are set at artificially low levels or where there
are low-cost production sources. In such electricity markets, the price
differential, which the merchant model depends strongly on, is either
non-existent or sufficiently insignificant to impede the company’s
ability to recover its investment.
Merchant lines are usually not part of the traditional planning of a
transmission system but are instead born of market opportunity. However,
despite their opportunistic nature, regulators and policymakers still
need to put in place the proper regulatory and market framework that
supports merchant lines if this is an option they want to pursue to
incentivise alternative financing for new transmission build.
Figure 7.1 Schematic representation of a merchant transmission
line
How it works
The assets of a merchant line/system are entirely owned by the private
party who invests or finances its construction. Merchant lines are
generally new construction, though it is conceivable that an existing
line/system is privatised and sold to a private party for them to maintain and operate. The
state-owned utility responsible for transmission infrastructure has no
financial interest in the merchant line.
Despite the private ownership, merchant lines are still subject to
technical compliance with grid code (if in place) and regulations in the
same manner as all power system assets. This includes approvals on
siting/permitting, design and technology to ensure safety, alignment, and
efficiency in the national power system. The extent to which a merchant
line is subject to regulation is primarily a function of the regulatory
framework of the host jurisdiction(s).
The merchant/line system is also privately managed and controlled, with
the owner/developer:
determining when to utilise the capacity of the line to transmit
power between markets;
directing all dispatch, operational, maintenance and repair
determinations for the line(s); and
negotiating commercial agreements, including pricing, with the
transmission systems on either end of the line to secure grid access.
Merchant line developers are responsible both for the initial capital
costs to purchase the rights-of-way, design and construction of the
project, and for ongoing operations and maintenance costs. The
commercial viability of a merchant line rests entirely on its ability to
capture value through power pricing arbitrage across markets or by
selling its capacity to third parties. In promoting this model, advanced
transmission network planning and coordination is important. Also, there
will be requirements to review policies that do not accommodate a
decentralised competitive wholesale market.
To secure a revenue source, there are three potential avenues for
securing customers in the merchant model.
Bilateral negotiation with a potential anchor credit-worthy
customer;
Competitive sale process with credit-worthy participants bidding; and
The real-time market mechanism through short term sale of the firm
and non-firm capacity, leveraging price arbitrage.
The customers of a merchant line owner/operator may include existing
generating company or generation project developers who would buy the
merchant transmission service to deliver the power from their generation
plant. The customers may be utilities, retailers or load-serving
entities with energy needs becoming anchor tenants giving them access to
an energy source. Also, customers of merchant lines may be energy
traders or owners of merchant generation assets that want to take
advantage of arbitrage congestion. More so, the implementation of
the merchant model is only possible where private entities are allowed
to hold a licence for the construction and operation of a transmission
infrastructure among other regulatory requirements.
There have been a limited number of merchant transmission lines
globally. Examples include a transmission line between the Australian
state of Victoria and the island of Tasmania; Path 15 connecting the
northern and southern sections of the California power grid; and
Montana-Alberta Tie Line.
Key challenges to adopting the merchant line model
The most significant challenge to financing merchant transmission lines is that it will be challenging to secure the
project revenues for the financing. Hence, a private company might need
to finance the project with little or no leverage (debt), or based on
other commercial activities. This is not optimal for the size of the investment required for
transmission assets.
This model may be attractive for governments depending on the needs of
the specific country. However, even if there is a well-functioning
market with limited credit risk (such as the Southern African Power Pool
(SAPP) market, where settlements are prepaid), there still needs to be a
consideration for broader risk, such as political stability, land
acquisition, and environmental and social risk. These risks, coupled
with the market demand risk, pose a challenge to most private investors,
which return expectations alone will not be able to overcome.
In places where there are no markets like SAPP, the regulations for
cross-border trades involving private participants are unlikely to have
been fully developed. Without regulatory certainty, it is difficult for
the private sector participants to develop a project on a merchant
basis, as regulatory certainty is required for long-term investments.
Industrial Demand-driven Model
In the industrial demand-driven model, transmission expansion is driven
by the electricity needs of one or more large industrial consumers. The
transmission line will be financed, built, and operated to serve the
industrial area where the large consumer(s) conduct their businesses. The relevant transmission line, once built, could remain in the hands
of the private sector or could be handed back to the transmission
utility responsible for the ownership and maintenance of transmission
assets (often in countries that consider transmission infrastructure a
public good).
As economies develop, there may be growth in a particular industry or
the discovery of a commodity in a region of a country where there is
little or no existing transmission infrastructure. The development of
the industry could underpin wider economic growth, which may be a key
driver in the procurement and financing of power and transmission
infrastructure to support industrial growth or a significant customer.
The key feature of this industrial-demand driven model is that the
project will be financed based on the creditworthiness of the industrial
consumer(s) and the strength of the industrial sector (e.g., the
commodity sector’s prospects).
Industrially driven development may not have initially been part of the
government’s overall strategic plan to electrify and connect its
population to the power grid. The same pattern is reflected in other
forms of infrastructure such as roads and railway lines. Particularly
where commodities are involved (e.g., mines or extractive industries) or
where there is a burgeoning industry (often based on a natural
resource), the private sector may engage the government to obtain the
relevant rights/licences to construct and sometimes operate the relevant
power and/or transmission infrastructure. Such lines may also be
initially constructed by the government and transferred to the private
sector as part of privatisation.
How it works
One or several large industrial network users located within the same area will
typically establish or be approached by a project company that will be
responsible for financing and constructing transmission assets used
to wheel power generated outside the industrial area. The power
generator may be a state-owned utility, the project company or another generator
that has entered into a standard power purchase agreement with
members of the consortium. The project company will prepare a
transmission expansion proposal for submission to the government
regulator. Depending on the structure of the transaction, the costs of
the network are allocated to (or among) the industrial user(s) either
based on a method established by the regulator or a method agreed upon
between the project company and the industrial user(s) at the time the
project company was established.
The industrial demand-driven model is similar to the merchant line
model in that it is subject to regulatory approvals on
siting/permitting, design and technology to ensure safety, alignment, and
efficiency in the national power system. Moreover, the project company
will also typically set the price for access to the line, subject to
regulatory approval.
However, unlike the merchant line model, the business case for the
industrial demand-driven models is based on the creditworthiness of the
industrial users of the network. Hence, the demand risk associated with
the merchant line model is reduced in the industrial demand-driven model
— the line is built primarily by or for the demand.
While the industrial demand-driven model is not yet a common method for
financing transmission infrastructure in SSA, it is included in this
chapter as reflective of the “status quo” due to the
strategic importance of the mining sector for the development of the
continent.
Key challenges to adopting the industrial demand-driven model
A key challenge to adopting the industrial demand-driven model is
determining the mechanisms for granting access to other network users
that are not the industrial users. It is inefficient to have
multiple transmission assets located in the same route. Hence, when the
country’s electricity demand increases, it may become necessary to
use the industrial demand-driven line to service distribution networks
or other generation companies located close to the line. When approving
an industrial demand-driven line that will be owned and operated by a
private company, the government has to anticipate a possible increase in
demand which will necessitate general use of the line. This will enable
an initial determination of how costs will be generally allocated in the
future when the line is opened to all transmission users.
Privatisation
Privatisation, otherwise called full divestiture in the context of this
handbook, relates to the transfer of full ownership in the transmission
infrastructure to a private-sector party. Privatisation may occur on a
single transmission corridor, by region or even in respect of the entire
transmission system operation in a country. Once privatisation has taken
place, the transmission company is typically restructured, management
processes are re-aligned, technology and infrastructure investments are
planned and the government influence on the operation and management is
limited to regulatory activities.
In deciding whether to privatise the transmission segment of its
electricity supply industry, a government should carefully evaluate its
goals for the sector and whether privatisation is the best model for
achieving these goals. Since the transmission business is typically
considered a natural monopoly, specialised regulation will be required
to monitor the activities of the privatised transmission business.
Further, the process of unbundling the vertically integrated utility,
breaking it up, and privatising the transmission segment will take
considerable planning, political will, and appropriate legal
reforms.
Privatisation may be an option to be considered under the following
prevailing conditions:
where there is a partial or full legal unbundling of the transmission
system operating function;
where a private-sector party is allowed by law to hold a transmission
licence for the construction and operation of the transmission
infrastructure; and
where there is an independent regulator to ensure technical
compliance and ensure appropriate tariff structures.
In other words, privatisation is more suitable to those jurisdictions
that have already commenced some form of unbundling and electricity
sector reform, and where the regulatory framework is conducive to
private sector participation in providing transmission-related services
and private sector ownership of the transmission assets (or where policy
decisions have been made to effect the above changes).
Figure 7.2: Forms and stages of unbundling of the transmission system
operator function
How it works
Privatisation can be implemented in at least three ways:
A sale of shares — where all or a majority of the shareholding of the
existing transmission company is transferred to a private entity. In
this option, the existing transmission company and its licences remain
unchanged and the transfer occurs at the shareholding level;
Figure 7.3: Privatisation Option: Sale of shares
A sale of assets — where there is a sale of the transmission business as a
going concern. In this option, the private party would be expected to
form a new transmission company and acquire the relevant transmission
licences in the name of the new entity; or
A statutory transfer — where legislation is passed imposing a compulsory
transfer of the transmission assets or shareholding, to a private
party. In this option, the transfer would be prescribed by the
legislation and any conditions attached to such law.
The government and the new owner may also enter into a government
support agreement, which protects the new private sector owner from
certain risks such as change-in-law, expropriation and foreign exchange.
Key challenges in adopting the privatising model
One of the key decisions that governments need to take at an early
stage is to be willing to divest from owning transmission infrastructure
that are assets with national security implications. This will entail
the loss of ownership in assets that are monopolistic in nature. This
monopoly does provide governments with intense power to control the
electricity supply of a country and provides for additional revenues in
some instances.
A second challenge is a fear that the privatisation process will result
in increased tariffs. A carefully managed privatisation effort will
ensure that results from long-term financial models are clearly
articulated to the public and key stakeholders. In some instances, there
may be an initial tariff increase due to increased operations and
maintenance activity and investments required to stabilise the
transmission business. However, long-term benefits and comparative
cost reductions need to be proven and stated. The usual intent of a
privatisation process is to increase the efficiency and stability of the
transmission business, which could ultimately lead to relative cost
reductions. If this is not achieved, the re-nationalisation of the
privatised transmission assets are likely to bring even more challenges
to the country’s power sector.
Another challenge is that staff and management of public utilities in
some instances fear the loss of jobs. However, some means are available
to governments and unions that can be utilised to guarantee job
security. If managed carefully and when widespread stakeholder buy-in is
secured, this challenge can be minimised. However, this is a
fundamental challenge and staff resistance may be at a level that may be
too difficult to overcome.
Case Study — The Copperbelt Energy Corporation
(“CEC”)
CEC’s business model has features of all three models — the
privatisation, the industrial demand-driven model, and merchant line
models — but especially, the industrial demand-driven model. CEC
was established as part of the privatisation of a previously
government-owned mining company. CEC’s transmission assets were
built primarily for the defunct mining company’s electricity
demand, and CEC currently sells power wheeled through its network to
many mining customers in Zambia. Further, CEC currently buys or
generates power in Zambia at a relatively lower cost and sells to mining
companies in the Democratic Republic of Congo.
CEC is a private company established in the context of the
privatisation of the Zambia Consolidated Copper Mines (ZCCM) in 1997.
Before being privatised, ZCCM owned and operated electricity assets
through its power division to address the needs of its mining operations
in the Copperbelt region of the country. When privatised, ZCCM was
divided into several companies and CEC took on the activities of
ZCCM’s power division including the role of operating,
maintaining, upgrading, and expanding the transmission asset to continue
the supply of electricity to the mines. CEC was later listed on the
Lusaka stock exchange in 2008 and became a full member of the Southern
African Power Pool in 2009.
CEC currently owns a network of more than 1,000 kilometres of
transmission lines at 220kV and 66kV, 43 high voltage substations and a
transmission interconnection between Zambia and the DRC. The company
purchases electricity from ZESCO, the Zambian national power utility,
and sells this across its transmission network to many Zambian mining
customers with a combined average demand of approx. 450 MW. CEC also
operates 6 gas turbine generators for emergency power supply with a
total installed capacity of 80MW.
Figure 7.4: A case example of an industry-driven transmission funding model in Zambia
The business model of CEC is not solely focused on transmission line
assets as the company diversified its activities in recent years and has
also developed generation projects and conducts power trading
activities. Nonetheless, CEC is a good example of an industrial-led
funding model as it was set up to address specific needs of the mining
industry in the Copperbelt region. Hence, the funding required for the
acquisition, maintenance, upgrade, and expansion of the network was
provided on the basis of the mining companies’ ability to pay for
electricity and the strength of the commodity sector. Moreover, the
characteristics of some of the world’s deepest copper mines
required consistency of supply to guarantee the safety of the
mines’ workers. The reliability standards of the network and the
readily available emergency power supply were therefore specifically
designed to respond to the specificities of the mining activities.
Summary of Key Points
Some other private sector-led models of procurement for transmission
infrastructure include:
merchant transmission lines
industrial demand-driven model, and
privatisations
These models are less likely to be adopted or operationalised in the
near term in the African context given other priorities of the sector
although they likely will form part of the future infrastructure
development in the African continent.
Merchant transmission lines
A merchant transmission line consists of one or more lines that
connect existing transmission grids/power markets or consumers that
were previously isolated. These transmission lines are entirely
private. Access to the merchant line is at the discretion of the
owner. It is not open to all transmission users. Merchant lines are
usually not part of the traditional planning of a transmission system
but are instead born out of the market opportunity.
Industrial demand-driven models
In the industrial demand-driven model, transmission expansion is
driven by the electricity needs of one or more large industrial
consumers. The transmission line is developed to serve the industrial
area where the large consumer(s) conduct their businesses. The relevant transmission line, once built, could remain in the hands
of the private sector or could be handed back to the transmission
utility.
A key challenge to this model is determining the mechanisms for
granting access to other network users that are not part of the
industrial users.
Privatisations
Privatisation relates to the transfer of full ownership in the
transmission infrastructure to a private-sector party. Privatisation
may occur on a single transmission corridor, by region or even in
respect of the entire transmission system operation in a country.
Once privatisation has taken place, the transmission company is
typically restructured.
Challenges to this model include a government's concerns about
loss of ownership of its natural monopoly and control, the fear that
privatisation will result in increased tariffs and the risk of
significant job losses with the public utility.
Sovereign support and additional credit enhancements, when needed, will
be required for the IPT, network concession, and privatisation funding
structures. As is the case for the financing of other types of
infrastructure assets, the need for additional credit enhancements and
sovereign support for the financing of transmission infrastructure will
be largely defined by the type of financing procured, and the
country’s and power sector’s economic viability. The
sector’s solvency will be instrumental in defining lenders’
requirements for providing financing, including which credit enhancements
are necessary and whether a sovereign guarantee will be requested.
Moreover, the lenders will have different considerations depending on
whether the transmission project is corporate- or project-financed. Some
of the key factors assessed by financiers in making this decision
are:
The creditworthiness of the transmission utility;
Cost reflectiveness of the end-user tariff;
The nature of the transmission charge (i.e., availability v.
utilisation based);
The project, concessionaire, or private utility’s ability to collect revenue;
Foreign exchange risks; and
Force majeure and political risks that may affect the repayment of
the financing.
Case Study — The Transener Transmission Network Concession:
Argentina
In 1993, the national government of Argentina granted a whole-of-grid
concession over the country’s existing high voltage system to
Transener, a privately funded transmission company. Transener’s
concession agreement provided for three forms of charges: connection
charges, line availability charges, and variable network charges. The
connection charges and line availability charges were mainly fixed
charges unconnected to the use of the assets or the quantity or
wholesale prices of electricity transmitted on Transener’s
network. However, the revenues from the variable network charges were
based on the use of the transmission assets. Specifically, these charges
are connected to the quantity of electric power which is lost as heat in
the transmission process and the wholesale price of that power.
To protect Transener from revenue losses arising from the volatility of
the variable network charges, the government guaranteed Transener $55
million per year in variable network charges for the first five years of
the concession. Any shortfall from the guaranteed amount would be
covered by a corresponding surcharge on the line availability
charges.
This case illustrates the importance for the government to ensure the
stability of the revenues in private sector-led funding structures.
While in the Transener case, the government did not undertake to cover
the revenue shortfall directly, it provided initial support against the
risk by a regulatory mechanism established in the concession
agreement.
Under the current market conditions in SSA, it is unlikely that it will
be feasible to structure the financing of a transmission infrastructure
without some form of government support and/or other credit enhancements
when one or more of these factors are perceived by the financiers as a
significant risk.
Although there is a wide spectrum of potential government support instruments and
credit enhancements, in the transmission infrastructure market in
Sub-Saharan Africa, only a limited number of instruments/ products have
been used to date. Nevertheless, stakeholders working towards a financeable
structure should consider all options when searching for risk-mitigating
measures.
Government Support
Before issuing a sovereign guarantee, governments should carefully
consider all available options and assess the magnitude of the payment
obligations, the related contingent liabilities and the impact these
obligations will have on the country’s overall debt
sustainability. Nonetheless, providing government support in favour of transmission infrastructure
financing can result in many potential benefits for the host government.
In making decisions about the support needed from the government, all
stakeholders should have an appreciation of the various factors the
government must balance when weighing the benefits and challenges of
granting credit enhancement.
The need for credit support from a host government may be required both
to address continuing payment risks and/or to address the ability to
satisfy termination payments. A sovereign guarantee can backstop routine
payments and give direct protection for termination payments and other
obligations affecting the transmission utility’s ability to repay
the financiers.
For the IPT model, the need for government support should be
anticipated since the model will use project finance to raise the debt
necessary for the transmission project. For the whole-of-grid concession
and the privatisation models, the government is also likely to be
requested to provide support although the scope may vary significantly
depending on the level of capital investment required to be made and the
specificities of the transaction. Furthermore, for the privatisation
model, more government support is typically expected at the early phase of
the privatisation of the transmission assets but should reduce within a
few years of operations by the private transmission utility.
Government support agreements can take various forms. An
“implementation agreement”, a “government
guarantee”, a “government support letter” or a
“put call options agreement” are just some of the names of
documents under which governments can provide support to a project.
Broadly speaking, they aim to achieve the same end, namely providing some
form of government support to a private sector investment and investors.
The government support agreement will be an important risk allocation
tool that is likely to be vital in terms of ensuring that the project is
capable of obtaining finance.
In some cases, the government support can extend to guaranteeing the
obligations of a state-owned transmission utility (e.g. in terms of
payment obligations). In almost all cases, government support will
extend to a government taking responsibility for certain
“political” risks, often described as events of
“political force majeure”. These risks include
expropriation, war, civil disturbance, and they are typically seen as
risks within the government’s control. Most government support
agreements provide for a form of termination compensation payable if an
ongoing political force majeure event occurs. Government support
documents also typically confirm the wider regulatory and enabling
environment and transaction or sector-specific promises made by the
government to facilitate private sector investment (e.g. as to matters
relating to the tax regime, investment protections, assistance with
permits etc.).
Sovereign Support for Termination Payments
Financiers are especially concerned about getting compensated if the
project is terminated. Most government support agreements are usually
structured such that upon termination, the government assumes ownership
of the project at a purchase price, also known as a termination payment.
This transfer of ownership can be executed either through a sale of the
transmission assets to the government or through a sale of all the
shares in the project company to a government-owned entity. The
constrained nature of the termination payment compensation is important
since this type of sovereign credit support is, in essence, a
“last-resort” option rather than a guarantee of actions or
payments that are in the regular course of business for a transmission
infrastructure project.
Termination of the project agreements (the TSA or the concession
agreement) and the corresponding compensation typically follow certain
defined trigger events. These events may be as a result of government
actions such as expropriation/nationalisation of the transmission assets
or payment default. In the case of termination as a result of government
actions, the project company typically terminates the project and
transfers ownership to the government upon payment of the compensation.
Termination may also be triggered by actions of the project company such
as persistent failure to meet key performance indicators. In this case,
the government may decide to terminate the project and assume ownership
of the project.
In addition to defining the trigger events, the government support
agreement must also carefully define the purchase price to be paid for
the project assets or of the shares in a project company upon
termination. The formula for the purchase price, also known as the
termination payment, will be directly tied to which trigger event has
led to the termination of the TSA or concession agreement.
For example, in the case of termination of the concession agreement due
to payment default by the state-owned utility, the purchase price will
likely include not only the value of the project assets and the
outstanding project debt but also the expected return for shareholders
in the project over a pre-agreed period. In the case of termination due
to the project company’s default, the purchase price may be
limited to just the outstanding project debt. The purchase price in the
case of termination for force majeure will likely fall somewhere between
these two extremes and may depend on who is directly impacted by the
force majeure as between the transmission utility or government and the
project company.
Direct agreements are agreements that give the lenders a right to
"step into the shoes" of the project company with the key
project contracts if the project company — or another contractual counterparty — defaults in
some way. While the counterparties to the government support agreement
will be the project company, the lenders will enter into a direct
agreement with the government related to the government support
agreement. This direct agreement will enable the lenders to step into
the shoes of the project company and directly enforce the rights of the
project company in the government support agreement in an event of
default.
This type of agreement is also common in a project finance context for
the IPT business model. It will enable lenders to take possession of the
project they have financed if there is a material default by the
developer. The lenders may then decide to select a new operator to avoid
complete failure of the project.
Non-sovereign credit enhancement options
Third-party financial institutions offer various credit enhancement and
political risk mitigation products in the context of transmission
infrastructure financing. These products can be used instead of, or
together with sovereign support to provide another level of credit
enhancement. They are particularly used where the credit of a sovereign
itself is not strong enough to offer the level of assurance required by
investors and lenders.
MDB/DFI Guarantees: MDBs and other DFIs can deploy a range of guarantees to
address the different types of risks for the financing of a
transmission line. DFI guarantees will typically support the most
critical financial obligations, such as the debt service obligations
on loans or project bonds or payment obligations linked to the
transmission infrastructure financing. MDB or DFI financing is also welcome by financiers as
their participation in a project serves as a political risk mitigant
with added positive effect on the bankability of a project.
Commercial Political Risk Insurance (PRI): This type of product offers coverage for political risks not
directly covered under the financing agreements or to backstop those
risks in addition to the government guarantee. Political risks are
associated with government actions that negatively impact the project
revenues by denying or restricting the right of an investor or lender
to use or benefit from the project assets. They include project
company expropriation, acts of war, civil disturbance, and breach of
sovereign obligations.
For a more comprehensive discussion on the various types and features
of Credit Enhancements, please see chapter 7 titled “Third-Party
Credit Support and Risk Mitigation” in the Understanding Power Project Financing handbook.
Summary of Key Points
Sovereign support and additional credit enhancements are likely to be
required for the IPT, network concession, and privatisation funding
structures.
The need for additional credit enhancements and sovereign support for
the financing of transmission infrastructure will be largely defined
by the type of financing procured, and the country’s and power
sector’s economic viability.
Before issuing a sovereign guarantee, governments should carefully
consider all available options and assess the magnitude of the payment
obligations, the related contingent liabilities and the impact these
obligations will have on the country’s overall debt
sustainability.
Providing government support in favour of transmission infrastructure
financing can result in many potential benefits for the host
government.
All stakeholders should have an appreciation of the various factors
the government must balance when weighing the benefits and challenges
of granting credit enhancement.
Financiers are particularly concerned about receiving compensation if
a project is terminated prior to its term, e.g. due to an unforeseen
political event. Many government support agreements are structured
such that upon termination, the government assumes ownership of the
project at a purchase price, also known as a termination payment.
Third-party financial institutions offer various credit enhancement
and political risk mitigation products in the context of transmission
infrastructure financing. These products can be used instead of, or
together with sovereign support to provide another level of credit
enhancement.
These products are particularly used where the credit of a sovereign
itself is not strong enough to offer the level of assurance required
by investors and lenders.
Transmission systems play a crucial role in moving electricity from
power plants to the end users. The farther the plants are from load
centres, the more important it will be to plan carefully the development
of the transmission infrastructure. With a growing focus on cheaper and
greener energy sources that are frequently located in less populated
areas, it is becoming even more imperative to efficiently transmit
electricity across the grid. In this chapter, we will discuss the
following:
The power system planning process;
The process for developing a Transmission Development Plan (TDP);
The need for the planning process to result in the selection of a
project with an appropriate financing structure; and
The process for procuring private sector participants.
Depending on the jurisdiction, the responsibility of the transmission
planning may shift from the transmission utility to the ministry,
regulator or another governmental agency. It also can be the
responsibility of the private sector, although this is rarely the case
in SSA. Even in the case of a whole-of-grid concession, the planning
function may be retained by the government and the execution of
identified projects may be done partly or fully by the public sector and
then handed over to the concessionaire.
The transmission planning process also allows the government to
identify the transmission lines that will be built in the upcoming years
and for which it will allocate significant resources. Thus, the planning
process also enables the government to identify lines not considered a
priority but that might be suitable for a merchant line or industrial
demand-driven funding model (regulation allowing).
This chapter will discuss the various steps from the power system
planning phase to the procurement of a transmission asset.
Power System Planning
There are many reasons why a government or a key public sector institution (e.g., transmission system operator) should conduct power system
planning. These include:
Efficiency: to avoid multiple studies and solutions, transmission
planning should be done by a central agency of government to better
integrate and use energy efficiently.
Optimisation: to avoid stranded or under-utilised assets in the
sector.
Reliability: to provide reliable power to customers and to avoid
underserved customers.
Cost-effectiveness: a holistic approach provides cost-effective
solutions.
Without a plan, there is substantial uncertainty regarding the
development of the power sector, and this increases the risks associated
with new projects.
The typical process flow for developing a new transmission line is
depicted below. This chapter will expand on each of these
processes:
Figure 9.1: Typical transmission project planning and development
Integrated Resource Planning
Integrated Resource Planning (IRP) is usually done by the Government.
This is done at a national level to develop a plan to meet all the
country’s national energy demands with available and planned
supply. It is a planning and selection process for electricity infrastructure
development, which assesses all options for providing adequate and
reliable electricity service to end users at the least system cost.
Some of the options considered by an IRP include new generation
capacity, energy efficiency measures, renewable energy resources, energy storage, and cogeneration. The IRP process considers the impact of any of
these options on the efficiency and reliability of the electricity
network. An IRP will provide a country with an energy plan for a
long period, usually 20 years. Although the IRP has a strong focus on
power generation requirements, it does account for high-level
transmission costing to connect generation power plants and load to main
collector substations.
One of the main objectives of the IRP is to identify the least-cost
generation to meet the macro power demand over a defined period. To project the growth of the demand for various energy sources,
the IRP will set macroeconomic assumptions such as GDP growth and
country inflation targets. The demand needs are then balanced with the
country’s potential energy sources and the cost associated with
their conversion into electricity. Some power projects that are already
being developed will be included in the IRP’s assumptions and used
as inputs into the analysis. The shortfall between the anticipated
supply and the projected growth will result in identifying opportunities
for new generation projects.
The IRPs usually require continuous updates based on changing
assumptions (especially demand forecasts and implementation schedule of
projects) and government targets. The output from an IRP process serves
to strengthen the level of knowledge of the sector stakeholders and
simultaneously serves as an input to future IRP processes.
Not all countries in Sub-Saharan Africa produce IRPs. In some
instances, they are not detailed. This often leads to the construction of adhoc generation plants. This unplanned approach can produce undesirable consequences such as
stranded assets in some areas of the system or the overload of a part of
the system. In addition, without a power sector development plan, it
would be difficult to identify in advance the need for transmission system requirements. As depicted in the flowchart (Figure 9.1), the IRP
is used as an input to the Transmission Development Plan which provides
for a more focused study of transmission projects.
Transmission Development Plan (TDP)
The TDP is developed by the transmission utility. In some instances,
there may exist an independent system operator but this is not common in
Africa.
The TDP utilises the IRP as an input. The TDP is needed to identify specific transmission projects which are
required to ensure that the electricity generated reaches the end users
and satisfies their needs. The TDP is crucial to the current and future
viability of a country’s power sector.
The planning process, as depicted in Figure 9.2, identifies the gap between the capacity of the
existing transmission system and the infrastructure needed to meet
current and projected demand. This process takes into account several
key factors including the historical demand, the quality of power
supply, the economic growth and development goals, regulatory
requirements, connections to new power plants, system losses,
undesirable voltage profiles and new industrial customers with high
demand. Regulatory requirements can include the need to meet the quality
of supply or system reliability standards or technical loss limits set
by the regulator. Regulations including the grid code may also impose
obligations on the transmission utility to connect, for instance,
renewable energy plants which are typically located in undeveloped parts
of the country and away from load centres. All these factors serve as
inputs into the analysis of options for transmission system development.
Figure 9.2: Graphical illustration of the planning process. The figure
is adapted from the process employed by Chile
Stakeholders
A wide range of public and private stakeholders with different
interests may be involved in the transmission planning process,
depending on the structure of the power system and the market
operations. The sector’s stakeholders will typically include the
Ministry of Energy, the economic planning ministry, power generators,
utilities, industrial customers, regulators, the investment community,
and the transmission utility(ies). While some of these stakeholders may
play active roles in the process (e.g., regulator, utility, cities,
etc.), others such as large industrials or building owners may only be
consulted as part of the data collection activity or for an alignment of
the different options available for resolving identified challenges in
the transmission system. Notwithstanding differences in each
stakeholder’s level of involvement, all stakeholders need to be
aligned in the development of the TDP to ensure that it is a national
and comprehensive plan.
Transmission system planning studies
The identification of projects for the TDP is underpinned by many
critical studies. The analytical work is mainly done by planning
experts. Some of these studies include a demand forecast; load flow
studies of existing and future systems; a short circuit analysis; system
stability studies; and resilience analysis.
For best results, the team of experts will be composed of different
experts such as economists, environmental specialists and engineers
experienced in planning, design, operations and maintenance. Existing
and prospective power producers must be consulted during this phase of
the planning process. The output of the analytical work is a list of
projects required to satisfy the evolving needs of the power system,
more specifically to ensure that generated electricity is transmitted to
end users in the most efficient manner and satisfies the demand needs of
end users.
The options assessment generally specifies the type of equipment to be built to improve the stability of the transmission system and the quality of
the supply. The assessment will also cover high-level capital and
lifetime cost estimates and the useful lives of these components on the
network. Lifetime cost may include losses, operations and
maintenance costs. The options may also already identify preliminary
route surveys and locations and their preliminary environmental and
social impact assessment. Detailed cost estimates, identification of
actual route of transmission infrastructure, and substation sites are
only required for the most viable options during project development
(e.g., through the project-specific feasibility study).
Route Identification
At an early stage, satellite images and available topographical data
may be used to identify one or a few feasible routes for further
analysis and investigation. Routes that have little chance of success
such as routes close to communities and nature reserves, can be avoided.
When one or a few viable routes are selected, further investigation may
warrant on-site activities such as “walking/driving/flying”
the route to confirm initial findings. At this stage, environmental
screening activities may also start and community consultations are
essential. The main outcome of this phase will be the specification of a few
routes from identified substations, which are low cost and have low or
manageable environmental and social impacts. More detail on route
identification, land acquisition and environmental and social impact
studies is provided in chapter 10. Land acquisition.
Figure 9.3: Some activities are undertaken for route
identification and selection
Transmission Project Selection
The next phase of the transmission planning process is the selection of
specific projects. In this context, the relative merits of the options
and alternatives generated from the analytical work are evaluated and
ranked. Considerations other than electrical parameters come into play,
including critical factors such as the environmental and social impacts.
The options and alternatives are therefore not only compared based on
technical efficiency and cost but also according to their environmental,
social and regulatory impacts. The set of viable, economical, and
environmentally feasible projects selected at the end of this phase
constitute the TDP.
The output of the TDP is a list of viable project alternatives for
meeting the identified needs of the power system. Out of this list, the
projects to be developed are selected. The case study below provides an
example of a TDP.
Case Study — Eskom Transmission Development Plan
Eskom’s Transmission business in South Africa is recognised
globally for its technical expertise and operations. Over the last 10
years, it has successfully constructed over 7800 km of new transmission
lines (added to its existing ~30000 km of transmission lines defined as
132kV and above) and increased the transmission substation capacity by
more than 37000 MVA. The transmission business follows a rigorous
planning approach. This is depicted in the diagram below (courtesy of
the published ESKOM TDP).
Figure 9.4: Eskom transmission development planning process
To achieve this, Eskom has to carry out many assessments such as
conducting strategic Environmental Impact Assessments (EIAs) and strategic servitude acquisition, working closely with the
government on the IRP development, independently determining its own
national and regional forecast at the Main Transmission Substation (MTS) level, and merging planning data with operational data to ensure
that reliability is improved. All of Eskom's planning is also
designed to meet the South African Grid code and to ensure that the new
generation is integrated. More than 10000 MW of new generation has been
integrated into the grid over the last 10 year with a substantial
increase expected for the next ten years. Eskom also develops a
strategic long-term Transmission Plan that is updated every 2 to 3 years
based on long term strategic assumptions over 20 years (instead of the
10-year planning horizon for the TDP which is updated annually).
Project Preparation
The planning process for transmission infrastructure will provide the utility or a ministry with a list of projects for implementation. At this stage, a
project can be identified for concept definition and initial design. A
typical project will follow the following phases:
Figure 9.5: Stages in project preparation
Each phase has clear outputs as defined in the diagram above.
It is important to note that in the practice, the transmission planning
and project preparation phases will have some overlaps in terms of some
of the outputs of the concept phase. However, a clearly defined project
concept is a key requirement to attract project preparation funding and technical assistance funding for the further stages.
Pre-feasibility analysis
The pre-feasibility analysis will focus on confirming several assumptions of the TDP route
identification process and high-level environment and social impact
assessment (ESIA) to confirm (or adjust) the preliminary analyses or
conclusions made in the context of the TDP. The pre-feasibility analysis is considered a high-risk phase of a
transmission project. It is therefore important to keep costs as low as
possible. The project will progress toward a full feasibility study if
the outcome of the pre-feasibility is satisfactory.
The private sector is rarely involved at this stage of the project
preparation process because of the significant uncertainty surrounding
the project’s viability and business case. For this reason, the
Government or transmission utility should always budget or seek funding
to provide for the cost of the pre-feasibility studies for the projects
identified.
Feasibility study
The feasibility study will be conducted on the route selected by the
pre-feasibility study and confirms or refines its conclusions through
detailed analysis and technical designs. Examples of activities carried
out at this stage may include power system analysis to establish the
technical feasibility, estimated power flows and scenario simulation for
losses under different operating conditions. Other activities include
in-depth data gathering, site reconnaissance activities including visual
inspection of the route and development of a digital terrain model,
alternate route analysis, geotechnical and other advance studies,
substation site selection and layout, risk assessment, stakeholder
engagement and route selection workshops.
At the end of the feasibility study, the project should have complete
initial design and cost estimates, a financial and an economic business
case, an ESIA, recommendations of contract procurement packages, legal structure
options and an approach for the financing of the capital works. All of
these activities will set the scene for project structuring to affirm
the bankability of the project.
At this stage, the inclusion of the private sector will be easier and
can be considered. However, to attract greater interest, the government
or utility can also consider conducting the feasibility study before
approaching the private developers. If private participation does not
gain traction at the feasibility stage, it should consider alternative
public funding options.
Funding for Project Preparation
Even when the private sector is invited to participate in the
development of a transmission infrastructure project, the expectation is
usually that the Government or the transmission utility will conduct
most of the project preparation activities. However, not all SSA
governments or SOEs may have the funds to conduct this exercise. For
this reason, project preparation funds or facilities (PPF) have been designed to provide funding for the project preparation
of transmission lines. Some of these donors/funds have specific
objectives such as the introduction of the PPP model or to help promote
regional integration, while others aim at encouraging projects that help
meet climate change targets. Hence, PPFs are not homogenous. A
non-exhaustive list of donors/funders can be found online at The Infrastructure Consortium for Africa.
Some of these fund sources also support capacity building, facilitate
and support the enabling environment to support infrastructure
investment by the public and private sectors, or a combination of both.
It should be noted that multiple funds may be used for the same project.
For example, a fund may be used to develop and conclude the ESIA study
while another may fund the technical feasibility report.
Most of these donors/funders have standard application processes and
documentation. At a minimum, the conceptual phase for the project should
be well-conceived before applications are made. Some donors/funders will
only fund projects that are ready for feasibility studies and expect the
concept and pre-feasibility studies to be complete at a minimum. A
high-level understanding of the sites for the substations (if required),
line routes, the financial and economic benefits and the expected cost
of the project should be understood and documented as a minimum.
Linkages to possible private participation, “green” energy
and regional integration should also be clearly articulated.
Procurement and the Private Sector
As stated above, the planning and early preparation work is commonly
undertaken by the government or state-owned utility. It may be possible
to start considering the inclusion of private sector participation at
the concept stage of a project. However, in most instances, the
high-risk nature of the project will deter most investors.
When the decision has been made to include the private sector, the
government needs to consider the procurement approach. This is discussed
in the following sections.
Procurement framework
The applicable procurement framework is closely linked to the source of
funding for that particular project. If the government or the
transmission utility conducts the project preparation (pre-feasibility
and feasibility studies) then the sovereign laws, guidelines, and
regulations become applicable. If the feasibility studies are funded by
grants from donors, then there will be a requirement to waive the local
requirements for the procurement and adopt the donor’s
requirements. This is often captured in a grant agreement between the
government and the donor.
It should be further noted that funding for the capital works must be
kept in mind. If funding is sought from DFIs for the capital works, a
review of all procurement activities will be conducted. If the local
procurement guidelines and regulations do not provide for competitive
procurement then it is advisable to adopt AfDB or World Bank guidelines
to avoid further challenges in raising finance.
For cross-border projects, choosing a local framework to govern the
procurement can be complex. Since most project preparation for
cross-border projects are donor-funded, most projects will adopt the
donor’s requirements. If there is an instance where development
activities are being funded by the government or the TSO, then it is
advisable for the project to still adopt an international DFI’s
guidelines to secure funding for the capital works at a later
stage.
Procurement structure
Having developed a TDP and completed project preparation activities,
the government and the procuring entity need to identify a procurement
approach. The government must decide earlier on which entity will manage
procurement. Below we will briefly discuss different types of
procurement that can be considered. The procurement approach, planning
and structure are discussed in great detail in the Understanding Power Project Procurement handbook.
A procuring entity might use a variety of procurement processes.
Broadly we use the categories described below as a framework for
discussing the different processes.
Competitive tenders
A competitive tender (also called an auction or competitive bidding
process) is a process initiated by a procuring entity to select the
sponsors that will develop a project through a competitive process. A
competitive tender requires investors to compete directly against each
other, on the same terms, for the opportunity to develop a project (or
projects). This procurement structure harnesses the power of competition
to achieve the objectives of the procuring entity. Bids are therefore
evaluated primarily on price, but may also include additional evaluation
criteria.
Figure 9.6: Generic roles of executing agency and bidders/contractors
in infrastructure procurement
Direct Negotiations
Negotiating a project with single or multiple developers without
inviting other interested parties to engage in a procurement process is
referred to as either a negotiated deal, a direct negotiation, or a
sole-sourced power procurement. A direct negotiation may be initiated by
the procuring entity or by the sponsors. In either case, the procuring
entity must ensure that direct negotiations are permitted under
applicable law while also considering the funder’s procurement
requirements to ensure that the capital works gets funded.
Summary of Key Points
All transmission projects start with planning.
Governments and transmission utilities are best placed to conduct the
planning across the sector. The reasons for this are efficiency, cost
optimisation, cost-effectiveness and reliability.
Stakeholder consultation during the planning process is recommended
to produce a more implementable and robust plan.
Integrated resource planning and transmission development planning
provide a prioritised list of projects that can proceed for project
preparation.
Governments can access various donor funds to assist with the
planning and project preparation activities.
Private sector participation in these transmission projects can be
procured via competitive processes and through direct negotiations.
Competitive processes will be more compatible with DFI funding.
A transmission line may be hundreds of kilometres long. The route may
cross land that is owned by the national government, state or regional
governments, public authorities, private landowners, or it could be
tribal or community-owned land. In many cases, it will be a combination
of all of these types of landownership. In addition to the transmission lines themselves, substations are
likely to be located along the line. Before financing can be disbursed
or construction can begin, rights-of-way, wayleaves or easements must be acquired along the length of the route and
ownership interests over the land on which substations will be
constructed must be acquired. These are all forms of “access
right” or ownership interest, that enables the contractor to build
along a pre-identified route and are usually granted by the relevant
landowner (whether this be a governmental authority or private
individual).
When it comes to substations, not only must the land on which it is
built be secured, it also needs to be accessible by road to get
construction materials to the site and for ongoing operations and
maintenance. If they are not, additional rights-of-way or
easements must be procured to provide access to the substations.
Acquiring these rights-of-way, easements, and ownership interests can
be costly and time-consuming in any country. Fortunately, a set of
good international practices have evolved for designing and siting
transmission lines, engaging in consultations with stakeholders that may
be affected by the project, acquiring interests in land through
voluntary purchases and sales, and ultimately, exercising rights of
expropriation (the right of eminent domain) in the event a landowner
refuses to sell a right-of-way, easement, or ownership interest.
The land acquisition process can present one of the most significant
impediments to implementing greenfield transmission infrastructure
development. The key is careful, methodical and early planning to
implement an efficient and expeditious land acquisition strategy. The
stakeholder best placed to negotiate and finance land acquisition will
depend on how that stakeholder is empowered to execute this activity, to
implement a project on time and at the lowest cost. With varying land
rights at stake, the matter is unlikely to be simple, and coordination
with stakeholders at all levels (from individual landowners to
communities, to the relevant lands ministry) will be fundamental to
ensure a smooth and successful process.
Planning for Rights-of-way
During the project preparation phase, one of the key activities is the
selection of the transmission line route to determine route
optimisation. At this early stage, utilities will start investigating
routing options for planning purposes. If there is a sufficiently strong
case or an obvious need for a transmission line in the long term, then
the utility may start pre-emptively acquiring strategic rights-of-way
for the eventual transmission infrastructure.
Identifying strategic rights-of-way does not involve a significant cost
outlay. At the start, it will be a desktop or satellite determination of
potential line routes, identifying the nature of the landownership along that route, and proceeding to landowner engagement. Where
it is possible to negotiate rights agreements with private landowners,
this can significantly assist in transmission line development in later
development phases. In some instances, it may be strategic to acquire
the rights to prevent obstacles that may impede project development
(e.g., to prevent settlements along routes that may be needed in future
years).
The relationship with landowners is critical in transmission line
development. With early-stage relationship-building activities, the
party responsible for the land acquisition, be that the governmental
authority or the private developer, will be able to manage the land
acquisition risk methodically. Without strong planning capacity, it will
be difficult for parties to proceed with strategic land acquisitions.
The acquisition of strategic rights does not provide an alternative to
detailed route selection engineering. This activity will need to be
undertaken as part of the project preparation activities and needs to be
budgeted accordingly. The availability of strategic rights-of-way can
however significantly reduce the time it takes to implement a
transmission project.
Phases for Route Identification
Route identification can help avoid choosing routes that are close to
communities and nature reserves or pass through difficult terrain. The
objective of this screening analysis is to identify one or a few
feasible routes for a more detailed analysis, with limited on-the-ground
activity.
The next phase of the identification and selection investigation may
warrant on-site activities such as “walking/driving/flying”
the route to confirm initial findings. Environmental screening
activities and community consultations may also start during this phase.
The goal of this scoping phase is to specify a few routes which optimise
technical feasibility, cost, and mitigate environmental and social
impacts.
The environmental and social impact assessment (ESIA) is an important
consideration that can ultimately determine available external financing
options. Aside from routing considerations, on-site soil and
geotechnical studies will be required, as well as ensuring the final
detailed design meets national grid code requirements.
Environmental and Social Impact Assessment (ESIA)
We have included a high-level depiction of the ESIA process in the
diagram below (as per the IFC environmental and social performance
standards):
Figure 10.1: High-level Environmental and Social Impact Assessment (ESIA) process
For transmission lines and land acquisition, the screening and scoping
stages are critical. Screening is a quick high-level analysis to
determine whether a full ESIA is required. If a full ESIA is required,
scoping determines which impacts are likely to be significant and become
the main focus of the ESIA.
In transmission projects, a full ESIA will most likely be required if
seeking external financing support from a publicly backed financial
institution. If significant physical or economic resettlement of
communities is needed, then a Resettlement Action Plan (RAP) will be
required. A deeper discussion of the ESIA and RAP processes is
outside of the scope of this book, however, both elements are closely
related to the land acquisition strategy and required for any
transmission infrastructure development.
The ESIA process must start at the concept stage or sooner as part of
the planning process. With an early start to the ESIA, the challenges
faced by projects can be managed and addressed. Transmission line
developments will be assessed against:
The process to prepare ESIA has been performed to the appropriate
level, with a plan to finance and implement identified mitigation
plans, including managing biodiversity;
Stakeholder consultation, including time and process allocated for
stakeholder engagement;
The process to prepare, finalise, and obtain agreement on the RAP,
including evaluating the adequacy of economic compensation and/or
physical relocation for identified affected individuals and/or
households; and
Availability of sufficient budget required for resettlement planning
and implementation.
By initiating the ESIA process early, the utility or government can
make informed decisions on the most optimal line route with due
consideration of these challenges. Some of these may be avoided through
strategic acquisitions as described above or can be avoided through
alternative routes.
Acquisition of Land for Rights-of-way
The responsibility for land acquisition will depend on the procurement
strategy for a transmission project, which is explored further in other
chapters. This responsibility is often best coordinated and executed by
the government, especially when the transmission utility or other
governmental body owns the transmission infrastructure. Depending on the
terms of a transmission service or concession agreement, private sector
developers can be allocated the responsibility for procuring land
rights. For example, the renewable IPP programme in South Africa
provides the option for the IPP developers, through a “self-build
option” to acquire the land required for their IPP project’s
transmission connection and undertake such transmission development
themselves (see case study in chapter 3. Common Funding Structures in the African Market). Ultimately, while the acquisition of land can be done by either the
government or by the private sector, it is wise to identify the actor
who is best positioned to efficiently and expeditiously acquire or
secure the land and rights of use, and to empower them with that responsibility. For example, some types
of land will require governments to exercise a “right of eminent
domain” to construct critical national infrastructure, a right
only the government can exercise.
Project preparation activities will normally include all of the studies
required to choose the line route options including the ESIA studies.
These activities can be funded through project preparation funds that
are available to governments and in some instances the private sector.
If MDBs or bilateral donors are providing concessionary financing to
construct the project asset, then land acquisition and ESIA related
costs may be included as a project capital expenditure which they are
willing to finance (for further discussion of project preparation funding, see chapter 9. Planning and Project Preparation).
Budgetary constraints faced by many utilities and governments can frustrate funding the acquisition of privately held land, especially to pre-emptively acquire
strategic land for future transmission lines. Timing of land acquisition
can greatly impact the negotiated price and therefore the cost of this
activity. Most investors will only fund the transmission projects at the
construction stage, and technical assistance grants are rarely available
for capital works or the acquisition of capital assets. Moreover,
acquisition of land during construction (or in general, after financial
closure) increases the land-related risks. Any way to secure the land
ahead of the financial closure is also desirable for all parties as
delays can prevent a project from being implemented, potentially
resulting in cost overruns and an increase in the overall cost of the
transmission line.
To the extent that the land acquisition is moved to the private sector,
the private sector may be able to fund the acquisition out of
development costs but are less likely to exercise the same leverage or
bargaining power than the government (local or national). The appetite
they will have to do this will depend upon how certain they are about
having the rights to execute the rest of the transaction (i.e., have
they been awarded a tender or concession to develop the project). In any
event, the private sector will need to work closely with the government
at both a local and national level to ensure adequate compensation is
being paid to affected peoples and landowners.
Role of the Private Sector
For many transmission projects, where the land in question is owned by a
community or by the government itself, the land acquisition risk is best
managed by the public utility or relevant ministry within the
government. This is not always the case and provided that they are granted
the right authorisations, private sector sponsors can take on the
responsibility for acquiring land, sometimes engaging a consultant to
advise and manage the process. It is important to note that ESIA and RAP
studies can often only be completed once land parcels have been
acquired, which adds to the lead time of preparing these types of
projects.
In projects anchored by a dedicated large industrial consumer, the
connection charge may be sufficient to allow for the payment for the
acquisition of the land rights.
For some IPP projects, the risk for the transmission connection to the
grid can be passed on to the IPP (e.g., generation-linked transmission
project discussed in chapter 3. Common Funding Structures in the African Market). The IPP will need to acquire the land rights and conduct all the
associated studies to ensure that the power generation project can
evacuate the power. It should be noted that these are usually shorter
transmission lines that simply allow for the connection to the existing
grid.
In an IPT or whole-of-grid concession/privatisation, the private
developer may be responsible for the grid expansion within the defined
concessioned area under a transmission service or concession agreement.
This could include land right acquisition for the projects. Governments
do however face the risk that if the landowners and the concessionaire
cannot reach an agreement, this might significantly delay investment
into the sector and this will hamper macroeconomic growth.
Expropriation and Eminent Domain
Governments in some jurisdictions may exercise their right to acquire
land via expropriation if needed for projects that are strategically
beneficial to the country.
These rights are sometimes called rights to “eminent
domain” or “compulsory purchase” rights. All of
these describe the power of a state, federal, or national government to
take private or community property for the public good or public use, on
a limited basis. This power can be delegated to government
subdivisions (or even to private companies) if legislatively
permissible.
When this right is exercised, it is expected that the government will
pay a fair market value for the right. Typically the land value
includes the value of any agricultural assets or use of the land as well
as the price of having to move any dwellings or other fixtures, but this
will be dependent on each country’s laws — and — if
funding is being provided by a DFI or MDB or donor agency, is likely to
need to meet the international standard of adequate economic
compensation.
Summary of Key Points
Transmission lines can be hundreds of kilometres long and may cross
land that is owned by the national government, state or regional
governments, public authorities, private landowners, or it could be
tribal or community-owned land.
During the project preparation phase, one of the key activities is
the selection of the optimum transmission line route.
Route identification can help avoid choosing routes that are close to
communities and nature reserves or passing through difficult terrain. The
objective of this screening analysis is to identify one or a few
feasible routes for a more detailed analysis, with limited
on-the-ground activity.
For transmission lines and land acquisition, the screening and
scoping stages are critical. Screening is a quick high-level analysis
to determine whether a full ESIA is required. If a full ESIA is
required, scoping determines which impacts are likely to be
significant and become the main focus of the ESIA.
The responsibility for land acquisition will depend on the
procurement strategy for a transmission project. But it is wise that the organisation which is in the best position
to arrange land acquisition is made responsible for it.
For many transmission projects, where the land in question is owned by a
community or by the government itself, the land acquisition risk is
best managed by the public utility or relevant ministry within the
government. Provided that they are granted the right authorisations,
private sector sponsors can also take on the responsibility for
acquiring land.
It is important to note that ESIA and RAP studies can often only be
completed once land parcels have been acquired, which adds to the lead
time of preparing these types of projects.
Governments in some jurisdictions may exercise their right to acquire
land via expropriation if needed for projects that are strategically
beneficial to the country.
The purpose of this section is to identify the most common risks
associated with private transmission projects/investments. The risks
summarised here are universal and should be considered regardless of the
business model which may be selected for each specific project.
How each risk is mitigated, however, may differ based on the
business model (see chapters 5, 6, and 7 for the discussion of risk mitigation for
each business model). Understanding the detailed risk allocation will be an important
part of the assessment of a project for a government, transmission
utility, or transmission investor. Such understanding will also inform
the policy case and the commercial case and impact the availability or
cost of financing for a project.
Identifying and allocating risks is a key part of the development stage
of private sector financing of any asset or project. How risks are
allocated between the parties will depend on the appetite that the party
has for risk. However, as a rule of thumb, risks are best allocated to
the party that is best placed to manage those risks. Risk allocation is
agreed upon in documentation between the parties. Where one party is not
able to fully take on risk, there may be mitigants that can be put in
place to minimise the impact of any risks occurring.
Project development often requires a significant investment of time and
money before proposing a project for direct negotiation or entering a
bid in a competitive procurement. From the point of project
identification onwards, there is a time commitment and funding required
to carry out all the activities which take place prior to financial
close. These include a pre-feasibility study, a review of relevant
laws and regulations, and conceptualising the financing scheme. As
the project matures, more substantial investments are made in
feasibility studies, social and environmental impacts assessments, land
acquisition/lease and a more detailed review of laws and regulations.
The time and substantial costs associated with these development
activities — and the risk of a project not achieving commercial or
financial close — represents a significant risk to investors. As a result,
before opening the transmission to private participation,
governments/regulators should be careful to ensure that they have fully
committed to an open and transparent investment solicitation process.
Any ambiguity or uncertainty will deter investors from taking on the
risk of developing a project proposal that will never receive fair
consideration.
To differentiate amongst the common risks, they have been grouped into
six categories: financial, land, technical, social and environmental, political and
regulatory, and dispute resolution. A diagrammatic summary of what
falls into these categories is set out below.
Figure 11.1: Categorisation of risks in developing and operating
transmission infrastructure
Financial Risks
The financial risks detailed below arise from private participation in
transmission infrastructure.
Demand risk
A substantial risk for any transmission project is demand risk. Demand risk is the risk that there will not be enough demand for
electricity from end users in a prescribed period to enable the private
investor to recover the capital costs of building the transmission
infrastructure. The risk is characterised as an under-utilisation of the transmission assets such that, over time, the transmission
assets do not generate enough revenue to cover their construction and
operating costs.
Private investors are very unlikely to accept any exposure to demand
risk: such exposure arises when the payment terms of a project are
linked to the use of the relevant transmission infrastructure (often
termed a “utilisation factor”). For example, the main private transmission business models discussed in
this book — independent power transmission projects (see chapter 5) and concessions (see chapter 6) — allocate demand risk to the transmission utility, the host
government, or electricity consumers.
Regardless of who bears this risk, the best way to mitigate it is to
ensure that the project includes assets that are essential and necessary
for the country’s requirements, as demonstrated by comprehensive
planning and feasibility studies. Hence, the focus for a private
investor is on how to build this asset as efficiently as possible and on
time, and to use the most efficient operating model.
Credit risk
The ability of existing utilities to make payments to private
transmission companies under long-term contracts is referred to as
“credit risk”. This type of risk is significant in the
African market since few utilities on the continent generate enough cash themselves to
recover their operational and capital expenditure costs. This is
due to a combination of high costs and low revenues. In extreme cases,
utilities may become functionally or legally insolvent. As a result,
utility credit risk is one of the most important risks which need to be
managed.
When evaluating credit risk, transmission investors will assess the
financial condition of the utility, the extent to which the end-user
tariffs reflect the cost of electricity across the entire value chain,
the utility company’s revenue collection rate, and its ability to
pay all stakeholders.
The capacity of the government to make a termination payment, even if
the likelihood of terminating the project is highly unlikely, will also
be part of the overall credit risk assessment, and mitigating this risk
will be necessary to access financing for the private transmission
project.
The formulation of termination compensation and buy-out prices are
discussed in more detail in the chapters on independent power
transmission projects and concessions (see chapters 5 and 6).
Inflation and interest rates
The multi-decade duration of most transmission investments exposes
investors to long-term economic risks arising from changes in inflation
and interest rates.
The costs of operating and maintaining transmission infrastructure will
vary over time and will be subject to inflation throughout a long-term
project. If a private investor takes responsibility for operating
or maintaining transmission infrastructure, then understanding the
treatment of inflation regarding these costs is an important risk that
is often reflected in the investment agreement.
Similarly, private investment in transmission infrastructure will usually involve a
large debt component that will be repaid during the long life of the
project. Lenders terms may include either fixed or floating
interest rates, and a lender may provide financing for the duration of
the project (most common in project financing for IPTs) or up until a
date in the future when the company investing in the transmission
project may need to refinance (which is typically the case for a
transmission concession). As with inflation, the risk that
interest rates may increase over time must be allocated within the
investment agreement. In some cases, these risks may be partly or
fully mitigated by hedging instruments.
Foreign exchange rates
While debt service and payment obligations for a transmission investor
are usually denominated in a reserve currency such as US dollars or
Euros, the transmission utility almost always charges its
consumers in local currency. The result is a currency mismatch
– the transmission utility pays for the transmission infrastructure in a reserve currency but earns its revenues in the local currency.
This mismatch is significant and strains the overall risk profile of an
investment.
Different business models for transmission investment deal with this
risk differently. However, the majority of investors, including
international lenders, with a mandate presently suitable for the sector
in Sub-Saharan Africa will be unable to take currency risk. Even where this risk is mitigated by a pass-through to the utility or government, an investor will need to consider the impact of foreign exchange risk
as part of the overall credit risk assessment described earlier in this
chapter.
Land
Transmission infrastructure, especially transmission lines, can cover
several hundreds of kilometres, adding to the complexity of securing
financing. Unlike power generation assets that are
location-specific, acquiring the rights-of-way requires considerable
political, community, social, economic, and environmental considerations
for each community or geographic terrain along the transmission line
route. Resettlement and the security of the infrastructure — from
both a public safety perspective and against vandalism or theft —
increases the risk of delays in, and escalates the costs of, developing
and delivering transmission infrastructure.
Please see chapter 10. Land Acquisition for further details on the land acquisition process.
Technical Risk
Transmission projects involve many technical risks. Identifying these
and apportioning them between a host government or transmission utility
and a private investor is an important part of agreeing to the terms of
any project. Private investors will then seek to mitigate and pass
through many of these risks by contracting with EPC contractors and/or
O&M providers, or through insuring against these risks where
suitable. In many cases, transferring some of these risks to a
private investor is a key benefit for a host government or transmission
utility and may form part of the rationale for introducing private
investment.
Construction and commissioning of assets
Most transmission projects will involve new infrastructure, including new or
upgraded infrastructure forming the basis of the project. Transferring construction risk to the private sector is likely
to be a key feature and benefit of most projects. This will
generally involve a private investor taking responsibility for cost
overruns resulting from construction.
Changes in the construction scope of work required may occur at different stages of the project and may have significant
impacts on the budget, schedule, and overall viability of the project.
Changes may involve the specification of certain components, the
designed redundancy, and interfaces with the existing or future
components of the power grid. Yet, the most disruptive scope change is
the change in the routing of the transmission line. This may be needed
because of numerous reasons including issues with land acquisition and
challenging geology.
The existence of a grid code helps to set the design specification. A
thorough feasibility study should help determine the required scope and
design specifications, as is described in chapter 9. Planning and Project Preparation.
The parties to a transmission project will
generally agree to the scope of projects before the signing of the
contract. Most transmission investors will seek to mitigate
construction risks with an EPC contract to transfer risk to a
construction company if it is better placed to manage them.
Interface Risks
Private transmission projects may be as simple as a single transmission line or may include multiple
lines. They may include new substations or the expansion or
refurbishment of existing ones. They may link to new or existing
power generation projects. All of these related infrastructure
assets may be held in either private or public hands. When
conceiving a new transmission infrastructure project, these related or
ancillary projects — and their ownership — must be taken
into consideration during the planning period of the transmission
project as the interface between the various assets may affect the scope
of the new transmission project. For example, a privately financed
line that is dependent on, and will be connected to, a remote generation
project will need to carefully assess the timing of the construction of
that generation project to ensure that delays on the generation project
do not adversely impact the timing of payment of wheeling or
use-of-service charges of the transmission line. A level of
coordination and interface management will be required for projects that
connect to one another.
Technology Risks
New technology risk is not common for transmission projects, as the technology is
relatively standard. However, soon new technologies will be
developed including smart grid capabilities and battery storage.
IPTs will not usually take on new technology risk as they are
difficult to finance without a proven track record. However,
whole-of-grid concessions and privatisation models do allow private
sector operators to experiment with new technology within their wider
business. Encouraging innovation and improvements is a possible benefit
of network concession models. Technology risks are reduced or eliminated
by ensuring that the specific technology has demonstrated good
performance and reliability in other projects of scale and similar
operating conditions. Risks associated with new technologies can
also be mitigated through appropriate supplier guarantees.
Operation, maintenance, and technical performance
Operating risks, especially availability and technical performance, need to be assessed.
Any private transmission financing business model which passes
responsibility for operating or maintaining assets to the private sector
will likely include key performance indicators (KPIs) for which the private investor will be responsible.
Failure to meet KPIs will generally result in financial penalties or revenue reductions
for the project company. Maintenance risks involve improper or inadequate maintenance. In most
private-sector business models this risk will be transferred to the
investor. The investor will then either employ its own staff to
maintain the assets or seek to transfer the responsibility and the risk
by hiring a contractor (either an independent maintenance company or
even the transmission utility) to carry out this function.
Accidents, damage, and theft
Accidents, damage and theft are risks throughout the lifecycle of a project including
construction, operation and maintenance, and need to be dealt with.
Responsibility for accidents will typically reside with the party
responsible for operations and maintenance. Damage and theft will
typically be the responsibility of the private sector asset owner,
though this can be mitigated through insurance products and adequate
insurance will typically be a requirement of lenders to the sector.
Social and Environmental Risks
The potential for transmission projects to impact surrounding
communities and environments is significant and gives rise to a number
of risks that must be allocated amongst the public and private parties
in any transmission investment. In general, a comprehensive social and
environmental impact assessment will need to be prepared in connection
with the construction of new facilities or the rehabilitation of
existing facilities. It is often advisable to begin this assessment at
an early stage, as part of pre-feasibility and feasibility studies, so
that serious social and environmental issues are identified early on.
In many cases, changes to the design of the project may mitigate
these issues. For example, alterations to the line route to mitigate
social and environmental impacts are common.
Social and environmental risks are typically grouped into construction-related risks and
operations-related risks. Some of the risks mentioned below are
present in only one of these two periods. Others are in
both.
Health and safety
Occupational, health, and safety risks that may arise during project
construction, operation, maintenance, and decommissioning should also be
assessed and allocated. Accidents could happen and adequate
precautions need to be taken to avoid them. Electrocution is probably
the most common injury but could be avoided with proper system design
and precautions. Electromagnetic interference (radio noise) is possible
and may require that transmission line rights-of-way and conductor
bundles be designed to ensure radio reception at the outside limits
remains normal.
Resettlement
If resettlement of persons is required to build and operate the
transmission project, a very thorough assessment is needed to ensure
that it is handled properly. Resettlement relates not only to landowners
but also to users of the land, particularly for agricultural or other
purposes. Lenders, especially development finance institutions, have
specific requirements on how social and environmental issues (including
resettlement) should be handled. One such example is the “Environmental, Health, and Safety Guidelines for Electric Power
Transmission and Distribution” of the World Bank Group.
Climate change
Finally, it should be mentioned that assessment of greenhouse gases as
a result of the transmission project is becoming more and more common.
Certainly, energy losses in the transmission line could be linked
to greenhouse gases. However, investments in transmission reduce
losses. Transmission is a key enabling infrastructure for renewables and
green power sources and as a result, investments in transmission may
contribute substantially to the reduction of emissions of greenhouse
gases.
Non-political force majeure events
A party to a contract may be affected by an event or circumstance or
combination of events or circumstances (including the effects thereof)
that is beyond the reasonable control of that party and that materially
and adversely affects the performance by that party of its obligations
under to a project agreement. Such events are known as force
majeure events. In civil law countries, the nature and
consequences of force majeure events are generally specified by law.
It may or may not be possible for parties to agree to change the
events that constitute force majeure events or the consequences of force
majeure events by contract. English law does not recognise the
concept of force majeure as a matter of law. As a result, the
parties to a contract governed by English law (and the laws of virtually
all common law countries) must agree on the events and circumstances
that constitute force majeure events and the consequences of those
events.
Force majeure events may include:
lightning fire, earthquake, tsunami, flood, storm, cyclone, typhoon,
or tornado;
fire, explosion, mudslide, or chemical contamination;
epidemic or plague; and
events that are analogous to political force majeure events but that
occur outside of the host country and do not directly involve the host
country.
If a party is prevented from performing by such an event, uses
reasonable efforts to overcome the effects of the event and continue
performing its obligations, and notifies the other party of the event
and its effects, then the time the affected party must perform will be
extended. If the force majeure continues for a prolonged period,
the parties may have the ability to terminate the affected project
agreements.
Political and Regulatory Risks
As discussed in chapter 12. Regulatory Framework, private transmission projects will need to obtain many approvals,
licenses, permits, and other consents from various public authorities to
be able to perform their obligations and exercise their rights. The
project company faces the risk that a license will not be issued, may be
revoked or that when the license period lapses, the license will not be
renewed. The project company would also be concerned about any changes
to the terms and conditions of the license or changes in law more
generally.
Political risks are generally mitigated under government support
agreements by way of termination compensation payments. The
formulation of termination compensation and buy-out prices are discussed
in more detail in the chapters on independent power transmission
projects and concessions (see chapter 5 and 6).
Licensing and permitting
A government support agreement (see chapter 8. Government Support and Credit Enhancement for more detail) will typically provide that the host government will, where
necessary, take appropriate action to ensure that its public authorities
issue the licenses, permits, and consents the project company is
required to obtain. The form of material licenses —
such as a transmission license — may be attached
to the government support agreement so that the project company will
have visibility of the terms and conditions that will be attached to
that license upon the execution of the government support agreement.
The issuance of key licenses will usually also constitute a
condition precedent to the effectiveness of the project agreements or to
the obligation of the project company to perform its obligations, such
as constructing facilities or taking control over operations and
maintenance. It is important to note the failure to approve and issue
permits or other regulatory approvals may eventually trigger an event of
default under the relevant IPT, concession, or similar agreement.
Change in law
The transmission utility and the host government will likely require
the project company to contractually commit to comply in all material
respects with the laws of the host country. The project company should
in turn be able to commit to doing so, at least by reference to
applicable laws at the outset of the project based on legal due
diligence and advice. The project company (and by extension its lenders)
will, however, find it difficult to give an unqualified commitment to
comply with laws to the extent that laws may change over time. This risk
arising from the impact of a changing legal environment over the life of
the project is referred to as a change in law risk.
The scope of change in law risk has evolved to include (a) the
introduction of a new law, (b) modification of existing law, and/or (c)
changes in the interpretation of the law by any court, tribunal,
governmental entity or other authority which has applicable jurisdiction
or regulatory oversight concerning the project or the project company.
“Law” in this context is often defined as covering a
comprehensive range of legislative, statutory and regulatory
instruments, orders, guidelines, and so on.
A change in law may impact the project company in many ways:
It may adversely affect the performance of a particular obligation
under the project agreement or render performance impossible.
It may adversely affect the project company’s revenue stream by
requiring the project company to incur a one-off capital cost or cause
an ongoing increase in the project company’s operating costs (in
each case, for the project company to comply with the relevant change
in law). Conversely, it may lead to a reduction in the project
company’s operating or forecast capital expenditure.
The general principle behind the allocation of change in the law risk
is that the project company should be left in no better or worse
position than if the relevant change in law had not occurred. This
protection is often subject to limits, such as the need for a
“material” impact on the project economics or exclusions for
changes in law related to human rights or environmental protection.
To the extent the project company is temporarily unable to perform an
obligation as a result of a change in law, this will not constitute a
project company default and any time limits imposed on the project
company will be extended accordingly. In addition, if the project
company incurs an increase in costs or decrease in revenue as a result
of a change in law, this will entitle the project company to receive
either (a) direct compensation to pay for or reimburse the project
company for such cost or revenue shortfall, or (b) an appropriate tariff
increase. Conversely, if the project company benefits from a change in
law, then an appropriate downward adjustment in the tariff will
typically apply. If a change in law renders performance under the
project agreement impossible, the project company will generally be
entitled to trigger the termination payment provided for in the
agreement.
Political force majeure events
A party to a contract may be affected by an event or circumstance or
combination of events or circumstances (including the effects thereof)
that is beyond the reasonable control of that party, and is to some extent
within the control of the host country, and materially and adversely
affects the performance by that party of its obligations under a project
agreement. Such an event may be known as a political force majeure
event. It may also be known as material adverse government action
or by some other name.
These events may include:
any act of war (whether declared or undeclared), invasion, armed
conflict or act of a foreign enemy, blockade, embargo, revolution,
riot, insurrection, civil commotion, or act of terrorism;
unless the project company is otherwise effectively compensated, any
failure by the regulator to allow or approve an adjustment to the
annual revenue requirement that the project company is authorised to
recover per the terms or provisions of the applicable licenses and the
tariff methodology guidelines;
the failure of a public authority to issue or renew licenses or the
modification of the terms of a license;
any strike, work-to-rule, or go-slow which is not primarily motivated
by a desire to influence the actions of the project company to
preserve or improve conditions of employment, and is part of a general
strike or industry-wide strike, work-to-rule, or go-slow; and
changes in law, including adverse changes in the tariff
methodology.
Prolonged political force majeure events may lead to government events
of default, which would typically entitle the project company to
terminate the project agreements and claim any termination compensation
that is payable upon their termination.
Dispute Resolution
Unfortunately, disputes do sometimes arise, even in the context of
well-structured transactions that have been implemented by parties that
were well advised by legal, technical, financial, and other specialist
advisors. The contracts that are discussed in this handbook are
all long-term contracts and the parties to them cannot always anticipate
the circumstances that may arise over a period that may sometimes exceed
30 years.
When a dispute arises, all parties will have an interest in resolving
the dispute as quickly, efficiently, and amicably as they can. The
purpose of dispute resolution mechanisms is to ensure that disputes are
resolved quickly so that the parties can put the dispute behind them and
continue to perform their obligations and enjoy their rights under the
contracts they have entered into.
Disputes arise for a variety of reasons. They may relate to
technical or financial issues, measurements of the availability of a
transmission line, or measurements of KPIs to name just a few.
Disputes may also relate to the interpretation of contracts, laws,
regulations, or licenses, or the interpretation of rights or obligations
that arise out of the intersection between contracts, laws, regulations,
and licenses.
Informal dispute resolution
The best thing parties can do when disputes arise is to talk to each
other. Ongoing dialogue among the parties after the project agreements
have been executed can help to resolve most disputes. If the
project level team is not able to resolve a dispute, discussions between
senior management of the parties to the dispute may be helpful.
Most project agreements impose an obligation on the parties to
attempt to amicably resolve issues in good faith through dialogue before
they use more formal dispute resolution processes.
Formal dispute resolution
Referral to technical experts
Many project agreements provide that a party may refer defined
categories of disputes to a technical expert. They may also
provide that any dispute may be referred to a technical expert if the
parties agree after the dispute has arisen, regardless of whether
the dispute falls within the defined categories of disputes that can be
referred to a technical expert by right.
Some project agreements provide that a technical expert appointed by
the parties will render a non-binding recommendation to the parties.
Although the recommendation is non-binding, it may assist the
parties in crystallising the issues and reaching an amicable resolution.
Other project agreements provide that a technical expert may issue
a decision and that the decision will be binding on the parties unless a
party effectively appeals the decisions by referring the dispute to
arbitration within a defined period after the decision has been issued.
Finally, in rare instances and in relation to narrower categories
of disputes, a project agreement may provide that a decision issued by a
technical expert is final and binding.
It is worth noting that the legal frameworks that support the validity
and binding nature of arbitration are well developed. In contrast,
the legal frameworks related to the determination of disputes by technical experts is
less well developed and that a decision may not be final and binding
even if a project agreement indicates that it will be if applicable law
does not provide that such decisions are final and binding. Care is
necessary in the context of cross-border projects because the laws of
multiple countries must be considered.
Expert determination is less suited to the resolution of disputes that
arise out of complex factual matters that require extensive evidence in
the form of documents or evidence from witnesses. Expert
determination is also less suited to purely legal disputes, in part
because most clauses that permit a party to refer a dispute to a
technical expert do not envision the referral of a dispute to
barristers, solicitors, or attorneys.
Independent engineers
If the transaction involves the appointment of an independent engineer,
the independent engineer may issue recommendations or opinions that can
help the parties resolve disputes. The list of issues that can be
submitted to an independent engineer can be agreed upon during the
negotiation of the project agreements. An independent engineer is
mandated in a separate agreement among the independent engineer and the
parties to the project agreement in relation to which the engineer is
being appointed. If the parties intend for an independent engineer
to play a role in resolving disagreements as they arise, it is advisable
to appoint an independent engineer at the outset of the project.
This avoids delays and disagreement as to the identity of the
independent engineer after a disagreement arises. It also means
that the independent engineer will have more background knowledge about
the project and may be able to issue well-informed recommendations and
opinions more quickly as a result.
Arbitration
Arbitration is used to resolve disputes that cannot be resolved through
informal processes or processes that involve a technical expert or
independent engineer. Unless the project agreements include a
provision that requires the parties to resolve disputes by binding
arbitration, the dispute would be submitted to courts that have
jurisdiction over the dispute. This is not an ideal outcome in the
context of international transactions because arbitral awards are much
more easily recognised and enforced by courts than decisions issued by
other courts.
The parties to a contract may choose from various sets of arbitration
rules to resolve disputes. Those rules include rules issued by the International Centre for the Settlement of Investment Disputes (ICSID),
the International Chamber of Commerce (the ICC), the United Nations
Commission on International Trade Law (UNCITRAL), and the London Court
of International Arbitration (the LCIA). Other arbitration rules
also exist, including under OHADA law. Each set of rules addresses issues such as the qualifications of
arbitrators, the number of arbitrators, the method of appointing
arbitrators, the confidentiality of the proceedings, the fees and costs
of the arbitrators, and many procedural issues.
The seat of arbitration
The project agreements should select the seat of the arbitration.
The seat sounds like it is where the arbitration will physically
take place, but it is important that the seat not be confused with the
venue of the arbitration (which is where the arbitration will take
place). The seat is important because the law of the seat will
(either favourably or unfavourably) fill in gaps not catered for by the
arbitral rules, will impact on the role of the courts regarding the
independence of the arbitrators, and might even override certain
arbitration rules.
The law of the seat can even influence the ultimate enforceability of
any award. Prudent contracting parties would undertake some due
diligence of the chosen seat.
Enforceability of an arbitral award
Parties often prefer arbitration to litigation due to the
enforceability of an arbitral award. An arbitral award may be enforced
in a country that is a party to the New York Convention (the Convention
on the Recognition and Enforcement of Foreign Arbitral Awards) and has
implemented the convention by passing its own internal laws regarding
the enforceability of foreign arbitral awards in a manner that is
consistent with the convention.
Summary of Key Points
Identifying and allocating risks is a key part of the development
stage of a private sector financing of any asset or project.
The majority of risks identified in this chapter are universal to all
types of investment in any country.
There are certain specific risks associated with the development,
construction, financing, and operation of transmission assets.
How risks are allocated between the parties will depend on the
appetite that party has for risk, but as a rule of thumb, risks are
best allocated to the party that is best placed to manage those risks.
Risk allocation is agreed upon in documentation between the parties.
Where one party is not able to fully take on risk, there may be
mitigants that can be put in place to minimise the impact of any risks
occurring.
Understanding the detailed risk allocation will be an important part
of the assessment of a project for a government, transmission utility,
and transmission investor. Such understanding will also inform the
policy case and the commercial case, and impact the availability or
cost of financing for a project.
More detailed analysis on the allocation of risks in IPTs and
whole-of-grid concession models are found in those respective
chapters.
Introduction
Regulatory frameworks are fundamental to the effective operations of
the electricity sector in any country. A predictable regulatory
framework is of particular importance to private funding structures
since the existing framework forms the assumptions upon which the
investment is made at the outset of the project and ongoing regulation
represents a risk over the life of the project.
The elements that define a well-constructed and transparent framework
include autonomy, consistency, and predictability. With these elements
legislated and demonstrated in practice, it will be easier to attract funding
of private business models and stimulate transmission infrastructure investment.
Improving the regulatory framework for transmission projects will also benefit the market more broadly by
incentivising efficiency and bringing down costs for consumers.
In addition to the general need for a well-developed regulatory
framework, the introduction of private investment in the transmission
sector will also require targeted changes to existing regulations to
address barriers that may otherwise make private investment
impossible.
In this chapter we will discuss the following:
the characteristics of an independent regulator;
how regulatory transparency can be achieved;
economic, market, and licensing regulations; and
reducing regulatory barriers to private investment.
Regulation by Contract
For certain private investments where the transmission project will
operate largely on an independent basis (e.g., whole-of-network
concessions and IPT models), it may be possible to finance a project
even if the regulatory framework is not fully developed. Both the
economic and technical regulations described in this chapter can be
defined directly in the project agreements, which is referred to as
Regulation by Contract. This does not foreclose the possibility of
developing a regulatory framework as that legislative process may
continue in parallel with the implementation of the project. There are
many cases in the power sector where one or two projects have led the
way and provided useful lessons learned that are translated into
long-term regulations. It is important to note, however, that the use of
Regulation by Contract should be limited as a widespread use would
result in a market with widely divergent regulation of different
projects. Any plan for wide-scale investment from the private sector
will require an independent and stable regulatory framework that governs
all market actors on equal terms.
Definition of an Independent Regulator
The independence of the regulator is a primary concern for transmission
project investors given the significant possibility for political
influence in the energy sector. As a regulated asset that supports the
broader public benefit of energy access, there is often an incentive for
political actors to artificially lower transmission and other energy
costs to generate goodwill with consumers (particularly ahead of elections). In its basic ideal form, an independent regulator will not be
subject to any political influences or special interest groups and will
be autonomous in its governance of the energy sector. Some of the
characteristics of an independent regulator are:
an independent board that has a duty of care to all sector
stakeholders;
independent funding mechanism via licensing fees;
resources and capacity to conduct regulatory activities (economic,
technical, legal, and compliance functions) without the need for
government or utility support; and
legislation that allows for accountability to all stakeholders
independent from the executive or legislative branches of
government.
As a general rule, legislative frameworks that govern electricity
sectors establish the regulator as a separate legal and independent
entity outside the ministry that is responsible for energy. Although the
government may establish policy objectives for the sector, the
independent regulator is responsible for ensuring efficiency,
transparency, and fairness in the management of the electricity sector
and benefits from the discretion that is required to achieve those
objectives and to balance the interests of investors and consumers.
Among other things, the concepts of regulatory independence and
discretion mean that a regulator is permitted by law to modify its
tariff guidelines at any time, yet with a reform procedure that involves
broad consultation with all participants, particularly sector
stakeholders.
How Transparency Can Be Achieved
A transparent regulatory framework can create credibility for the
regulator and the regulatory decisions it makes. Even when service
providers are all public entities, stakeholders including the
government, consumers, and utilities are more likely to express
confidence in the regulator if its decisions are guided by clear rules,
procedures, and methodologies and if stakeholders participate in the
decision-making process.
Transparency makes it easier to attract private investment in financing
through any of the available business models discussed in this handbook.
This is because private investors are more likely to choose legal and
regulatory frameworks in which their rights and obligations have been
clearly defined and the decisions of the regulator are predictable.
Measures to achieve and enhance transparency in the regulatory
framework include clarity of the rules and procedures of the regulator
and the rights and obligations of regulated entities, the autonomy of
the regulator, regulator accountability to stakeholders, predictability
of regulatory decisions, broad stakeholder participation in the
regulatory process, and open access to information about the
process.
Clarity of roles, rights, and obligations
Regulatory transparency can be enhanced when the roles and objectives
of the regulator are spelt out in primary legislation and other
instruments such as contracts. The rights and obligations of the
regulated entities also need to be clearly stated so that expectations
are clear to all stakeholders. This feature of the regulatory framework
is particularly important to private developers and their
financiers.
Autonomy of the regulator
Good regulatory governance requires that the regulator is protected by
law and in practice from interference from political actors,
policymakers, and special interest groups. This may be achieved through
various measures that ensure that regulators are not funded through
government budgets or by the utilities, and balanced stakeholder
representation on the board of the regulators.
Accountability to stakeholders
To avoid abuse or the perception of abuse of its autonomy, a good
regulatory framework should create the framework for stakeholders to
challenge the decisions of the regulator, and most importantly, to
obtain redress when the decisions are not per the rules and
procedures.
Predictability of regulatory decisions
In a good regulatory framework, the decisions of the regulator will be
predictable. This means that regulatory decisions are made under
established rules, methodologies, and processes. It calls for clearly
spelling out in regulatory documents - including licenses and contracts- the factors that feed into the decisions of the regulator. These factors
may include definitions of parameters such as the rate base, price
adjustment formulas, and timetables of events.
Stakeholder participation
Broad stakeholder participation in the regulatory process enhances
transparency and the legitimacy of the regulatory framework and bolsters
consumer confidence that the regulatory system will protect them from unreasonably high prices or
poor quality of service. Typical stakeholders will include regulated entities, non-regulated ones, consumers, policymakers, and
other public authorities. These stakeholders should be encouraged to
participate actively in the regulatory decision-making process, to
provide regulators with as much information as possible about their views and about the impact that a
regulatory decision would have on them.
Open access to information
Open access simply means that the laws, rules, processes,
methodologies, and consultation papers that inform the decisions of the
regulator and the decisions themselves are readily and openly available
to stakeholders and the general public. This is one way to enhance the
transparency of the regulatory framework and foster stakeholder
participation and stakeholder confidence in the regulator and regulatory
decisions.
Functions of a Regulator
Economic regulation
Economic regulation is needed in areas where no functional competition
is possible. Electricity networks are a prime example of this lack of
constitution since they typically constitute a natural monopoly and
require regulation to limit monopoly pricing and to set incentives for
efficient performance.
Economic regulation typically involves ensuring the financial
sustainability of the utility through tariffs that are cost-reflective
and incentives for the efficient cost of operations. It also allows for
utilities to have returns that allow for future investments and still
balances the requirements for affordability to ensure access for all.
The necessity for economic regulation that balances the need to limit
monopoly effects with the financial sustainability of the utility
applies equally to both public and private transmission companies.
Methods for economic regulation
Some of the methods used for economic regulation by regulators
include:
Rate of return (ROR) regulation: At the basic level this method allows the regulated entity to
recover its justifiable prudent cost and is allowed a return on the
regulated assets (or rate base). Under this method of regulation, regulators evaluate the firm's
rate base, cost of capital, operating expenses, and overall depreciation
to estimate the total revenue needed for the firm to fully cover its
expenses. It makes room for clawbacks and claims for over- and
under-recovery of cost, typically through clearing accounts. It should
be noted that in some jurisdictions the term cost of service regulation,
or COSR, is used. The most commonly used term in Africa, however, is
RoR.
Incentive-based regulation: This method determines the revenue requirement for the
transmission utility using a future period called a control period. The
control period is a long interval between tariff reviews, usually 4 or 5
years, within which the revenue requirement is frozen. In the control
period, tariffs are allowed to increase at a rate that comprises the
difference between the country’s annual consumer price index (CPI)
or inflation rate and a productivity factor. The goal of this method is
to ensure that at the end of the control period, the transmission
utility’s allowed revenues equate to its costs, and efficiency
gains are passed on to the consumers in the next control period.
This model can take either of two approaches: the price cap and the
revenue cap approaches.
Price cap regulation: Sometimes referred to as CPI-X, this method attempts to adjust the
utilities’ prices according to the price cap index that reflects
the overall rate of inflation in the economy, the ability of the
operator to gain efficiencies relative to the inflation in the utilities
input prices, relative to the average in the economy.
Revenue cap regulation: This method allows the utility to change its prices as long as its
revenue remains below the cap set.
The effective application of these methods will lead to a predictable
methodology for calculating the economic return for transmission
projects and make it easier for potential investors to assess the
commercial viability of any given project.
Cost recovery: transmission tariff considerations
Efficient regulation will be required to determine the price (cost) of
transmission through a transmission tariff that will be ultimately borne
by the electricity end user. The transmission tariff will be designed
using principles that enable fair allocation of the cost of transmission
between generation and consumption, reduce the investor’s risk of
cost recovery, incentivise network users to make the best decisions on
the location of new generation and load, and reduce system operating
costs.
Figure 12.1: Elements of transmission tariff regulation
development
When the transmission costs are clear and fairly allocated, it becomes
easier to attract financing through any of the available business models
discussed in this handbook.
To attract financing for transmission, governments will have to
consider how their respective electricity market structures affect the
transparency of their transmission costs. The regulatory tariff models
and pricing methodology used in Sub-Saharan Africa to calculate the upstream
costs of transmission depend largely on the structure of the electricity
market. Thus, vertically integrated electricity markets with little or
no unbundling or competition differ in their approach to transmission
pricing from unbundled markets with a partial or full competition. This
impact of the market structure on transmission pricing affects the
extent of regulation for and transparency in the cost of
transmission.
In vertically integrated monopolies with no market competition, the
costs associated with transmission are often unclear. While it may be
possible to determine the fixed costs of new transmission lines, the
variable costs of operating and maintaining the grid may not be easily
separated from the operation and maintenance costs for associated
generation plants and the distribution system. Corporate and
administrative costs also remain bundled.
Figure 12.2: Current degrees of transmission tariff pricing in SSA
according to market structure
Further, limited regulation of transmission pricing is seen in most
countries that have introduced competition in generation while retaining
a vertically integrated monopoly structure. The regulator ensures that
the connection charges for a new generator — typically
an IPP — cover the costs of constructing, operating,
and maintaining the network facilities that are strictly required to
connect the IPP to the monopoly’s network. However, the costs
related to the use of the system by both the generators and the utility
are not clear. Thus, proper cost allocation may not be feasible under
current tariff structures in markets with vertically integrated
utilities and new regulations may be needed to establish a predictable
methodology for transmission pricing.
Transmission pricing is clearer in some countries that have undergone
full legal unbundling: separation of generation,
transmission, and distribution functions into different legal entities.
The laws in such countries also establish independent regulators that
create regulatory frameworks to allocate the benefits and costs of using
the transmission network among the various participants in the market
and recover the costs of investment. Yet, the degree of transmission
cost transparency in such markets depends on the extent of the
regulator’s independence and its ability to design and implement
cost-reflective tariffs.
Nonetheless, all countries regardless of market structure can regulate
and achieve transparency in transmission costs. Costs of transmission in
vertically integrated monopolies can be regulated and be transparent
without a full legal unbundling exercise. This is possible if the
existing monopoly utility is required to maintain separate accounts for
the various services it renders (generation, transmission, distribution)
which are then monitored by an independent regulator. This introduces
transparency and predictability without the need to fully unbundle the
legacy utility in a market.
Case Study — Mauritius
The legal and regulatory framework established by the Mauritius
Electricity Act, 2005 (as amended, 2020) contemplates the
existence of an independent regulator (the Utility Regulatory Authority)
and a requirement that a licensee who provides more than one electricity
service should keep separate accounts and publish separate financial
statements for each electricity service. Hence, the vertically
integrated utility will keep separate accounts for generation,
transmission, and distribution. Such practice — known
as accounting unbundling — can enable a vertically
integrated utility to avoid cross-subsidisation of costs among its
respective businesses, determine the true cost of transmission, and
publicly disclose such costs. The regulator is also better equipped to
properly allocate transmission costs to other network users such as IPPs
and bulk purchasers.
Market Regulations and Compliance
An electricity regulator also performs in some markets the function of
a market regulator in addition to the economic regulations. This
includes for the transmission business the development of the grid codes
that govern the technical specifications and performance requirements.
Adherence to this is usually specified in the licence.
A regulator also plays an important role in monitoring compliance to
licensing conditions and other legislation. To do this effectively, the
regulator will need to be appropriately resourced and have the necessary
legislative powers to impose sanctions for infringements.
As electricity markets become more liberalised, the functions of the
regulator will need to be reinforced. With a multitude of stakeholders
and consultants being a foundation of regulatory processes, the
regulator’s ability and resources to undertake these activities
need continual focus. A regulator without the resources can quickly lose
its independence, even if in some instances this is not total
independence.
Licensing
Another function that a regulator performs is to issue licenses. Some of these licenses, permits, and consents apply to virtually any
type of business. A business license may be required by the localities
in which a business owns property, operates, or has an office, for
example. Planning, location, and construction permits are likely to be
required to construct transmission facilities, substations, offices, and
other facilities. At the other end of the spectrum, some licenses,
permits, and consents are specific to the power sector, and to
transmission in particular. A transmission license is a good example of
a license that is specific to the transmission sector.
The transmission license typically authorises the holder to own,
construct, and operate physical installations for transporting
electricity from a production point to a consumption point, either
within the country or outside the country. In many African countries,
cross-border transactions will not fall under the remit of the local
countries’ regulator and may be regarded as an unregulated
business.
The system operation license authorises the holder to engage in
activities that ensure the reliability of the entire network. Thus, the
system operation licensee will manage electricity flows on the network,
and undertake non-discriminatory generation scheduling, commitment and
dispatch, transmission congestion management, transmission outage
coordination, system planning for long-term capacity, and procurement
and scheduling of ancillary services. The system operator does not own
or operate physical transmission facilities and has no financial
interest in the electricity flow on the transmission lines.
Regulatory Implications for the Private Sector
This section will discuss the regulatory framework required to attract private investments in transmission. While the bulk of private investment in power infrastructure is
directed to generation projects, governments and regulators are
increasingly moving towards the introduction of private participation
into other segments of the power market, such as transmission and
distribution. Even with private participation, the need to maintain the
stability and accessibility of power markets remains. Regardless of the
mix of public and private participation in the power market, a
regulatory framework that establishes market rules, prohibits and
provides protection is an important focus for governments
and regulators.
Removing entry barriers to private investments
Since electricity transmission infrastructure has traditionally been
managed as a public asset, the regulatory framework must often be adjusted to specifically authorise
private participants to undertake grid activities. Grid activities
include planning for transmission projects, construction of new
transmission infrastructure, maintenance planning, and system operation.
Some jurisdictions divide these activities into two licenses which may
be held by the same entity — a transmission license
and a system operation license.
If a country’s legal and regulatory framework contemplates that
only the state-owned utility will perform the activities listed above as
strictly “transmission license” activities, it will be
difficult to attract private investments into the transmission segment
of the electricity supply chain. The business models discussed in this
book are only possible if the electricity laws and regulations are
drafted to allow private entities to hold “transmission
licenses''. These licensees can coexist with state-owned
utilities who may also provide transmission and/or system operator
functions. However, the licensing regime must ensure that private
entities which undertake strictly transmission activities allow
non-discriminatory connection to the installations they own and operate. The licensing framework should also clearly establish the steps for
obtaining a transmission license and the costs involved.
Secured interests in transmission assets
One significant change in the regulatory framework for transmission
systems that must be anticipated with the introduction of private
investment is the need for investors to obtain a secured interest in any
transmission assets that are covered by a license, concession, or any
other business model. This may be a significant departure from existing
frameworks that assume transmission assets are to be held by a public
entity on behalf of the state. The form of secured interest that
investors require may vary significantly, based upon both the project
structure and the type of financing. In general, however, the regulatory
framework should anticipate the need to grant interests to private
parties in the physical assets (land, equipment, etc), legal assets
(operating license, sales/marketing agreements, etc), and financial
assets (tariff payments, receivables, etc). Without this security, the
investor will be unable to demonstrate to their shareholders or lenders
the financial security necessary to fully fund the project's
development and the cost recovery potential.
Currency risk
As discussed later in this book within the context of financing,
privately financed transmission projects often require that the investor
borrow funds in either local currency or reserve currency. The local
currency is the currency of the jurisdiction in which the project is to
be constructed and operated, and reserve currency is a currency held in
significant quantities as part of governments’ or
institutions’ foreign exchange reserves. Reserve currencies, such
as U.S. dollars and Euros, are commonly used in power and infrastructure
transactions. As a result, any regulatory framework that intends to
attract private investment in transmission infrastructure must also
authorise the payment of transmission tariffs in either local or reserve
currencies (or possibly a combination of both) to ensure that the
private financing terms of the project are compatible with the publicly
regulated payment structure. For additional detail on currency risk in
private projects, see chapter 11. Common Risks.
Dispute resolution
With the introduction of private participation in the transmission
segment of a domestic power market, it is often necessary for the
regulatory framework to accommodate the need for alternative forms of
dispute resolution to quickly and fairly resolve any issues that arise
at the contract or operational level. For example, as new technologies
and operational standards are introduced by private parties, the
regulatory framework may authorise the appointment of independent
engineers to help reconcile any conflicts between legacy and modern
systems. Similarly, if a major dispute were to arise between public and
private parties, it would be expected that a neutral dispute resolution
system, such as commercial arbitration, could be utilised to resolve the
dispute, an option that would need to be specifically authorised in the
regulatory framework (public entities may also be required to waive
their sovereign immunity protections to enable the enforcement of any
arbitration awards). For additional detail on dispute resolution, see chapter 11. Common Risks.
Summary of Key Points
An effective regulatory framework for both public and private
transmission projects should be transparent, consistent, and
predictable.
An independent regulator is critical and should not be subject to any
political influences or special interest groups to facilitate
autonomous governance of the market.
Energy regulators provide vital functions for the sector such as
economic and market regulation, licensing, and compliance.
In addition to the general need for an effective regulatory
framework, private projects will require specific regulations to
protect investors.
In limited cases, a private project may be negotiated in a market
that lacks a clear regulatory framework through Regulation by
Contract.
Deep Dive into Transmission Pricing
As explained in this chapter 12. Regulatory Framework, one of the primary functions of an independent regulator is to
establish the pricing that the transmission utilities, be they private
or public, can charge to generate revenue. This revenue will then cover
the transmission utility’s costs, namely, the network investment
costs (including a specified return on the capital deployed), operation
and maintenance costs, ancillary service charges, and administrative
costs.
This section of the book presents a summary of the most common
methodologies utilised by independent regulators to establish
transmission pricing. While any application of a pricing model will
require careful study, economic modelling, and significant consultation
with all market stakeholders, this section should provide a helpful
overview of the diversity of pricing strategies available to regulators.
This section is especially relevant for the whole-of-grid concession
funding structure as the pricing of the transmission charge by the
regulator will be critical for the successful implementation of the
business model. Note, however, that the level of technicality of this
subject matter is high and goes slightly beyond the original intent of
this book.
Tariff Setting Process
The basis for determining the transmission utility’s allowed revenues depends on the tariff model adopted by the
regulator. As detailed in this chapter, there is a range of tariff
models that may be deployed by the regulator. However, before
investigating each model, it is important to note that any uncertainty
in the process adopted for tariff making is itself considered a risk for
private investors.
A key feature of the revenue models for private transmission projects
is the periodic regulatory review of the tariffs. At the outset of a
project, the tariff will be established, based upon the allocation of
existing assets to the private operator (in a privatisation or
concession model). However, over the life of the project, as the need
for additional investments in the transmission network/segment are
identified, the regulated tariff will need to be reviewed. Additionally,
between reviews, the existing regulated tariff may be allowed to
increase by an escalation factor that reflects inflation or other
changes in economic growth. The investment agreement may also include
key performance targets for the private transmission project, which may
also be adjusted over time as the assumptions underlying those
performance targets evolve with appropriate rewards or penalties
attached to the performance targets.
Given the significant need to treat tariff setting as an ongoing
exercise rather than a one-time event, it is critically important for
the regulator to communicate to the market how it plans to engage in
this process and invite feedback to build trust in that process. Some
areas of concern include: the model applied in the valuation of the
transmission assets, the establishment of a reasonable return on
invested capital, and the characterisation of the nature of new assets
that are included in the regulated asset base.
Tariff Methodologies
In general, the process for transmission tariff design is divided into
three phases:
Establishing the allowed costs (annual revenue requirement) of the
transmission utility through any of the revenue regulation models for
network monopolies.
Deciding how the transmission utility’s revenue requirement
will be allocated among network users in the form of connection and
use-of-system charges.
Designing the format of the charges.
The methods for establishing the allowed costs have been briefly
described in the main chapter ‘Regulatory Framework’. These
include the cost of service model and the performance-based regulation
model. However, the various considerations and calculations in these
models are not discussed in detail in this book.
After determining the transmission utility’s costs or revenue
requirement, the regulator allocates these costs among network users
through transmission charges. Transmission charges can be broadly
divided into two categories:
the connection charge; and
the transmission-use-of-system (TUOS) charge.
Connection charges
Connection charges are designed to recover the transmission
utility’s costs for constructing and maintaining the connections
and associated transformers required by individual generators and
wholesale buyers. Regulators typically take various approaches to
recover the connection costs. These approaches depend on whether new
facilities are needed to connect the network user and the extent to
which the new connection facilities will benefit other users of the
transmission network.
If new facilities are not needed, then there is typically no network
charge. However, if new facilities are needed, whether the connection
charge will be separated from the TUOS charge depends on whether the
connection costs are shallow or deep.
Shallow connection costs cover the cost of new facilities dedicated to connecting a network user
to the grid. The connection charge allowed by the regulator will cover
the cost of the meter, any transmission substation, and the cost of the
usually short line between the network users and the transmission
utility’s network. The regulator may decide to levy those charges
to be paid upfront or to spread the payments as monthly costs over time.
Such costs may also be shared among all users connected to that specific
node in the transmission network.
Deep connection costs cover facilities that benefit existing network users or future network
users. For instance, system upgrades or reinforcements may be necessary
because the network is congested at a certain connection point. New
lines and associated transformers may also be needed when there is a
long distance between the new IPP, distribution company, or industrial
consumer and the preferable network connection point. In this case, the
new facilities may be deemed part of the transmission network instead of
a connection. Regulators typically include deep connection costs as part
of the TUOS charge.
TUOS charge
Since the TUOS charge covers the cost of network investments other than
shallow connection costs, operation and maintenance of the network, and
the corporate and administrative costs of running the transmission
business, the TUOS is the main transmission charge which the regulator
must determine how to allocate among network users.
In allocating the cost of the network, the regulator aims to ensure
that the method used is simple and transparent, non-discriminatory,
fair, enables recovery of the cost from both present and future users of
the network, and sends proper location signals to users in the network.
There are various approaches used globally by regulators or suggested by
academics for transmission cost allocation, and no approach is
foolproof. Some of the common approaches used are postage stamp,
wheeling, and distance-based methods.
Postage stamp method: this is the simplest and most common method of transmission
cost allocation. Using this method, the regulator allocates the TUOS
costs among all network users through a uniform charge that applies
regardless of the location of the user or the transactions involved.
Thus, every generator and/or distributor receives the same charge per
MW or MWh injected into the system, or per hour of the availability of
the transmission network. In some countries, the regulator divides the
charge into proportions between generators and distributors/bulk
purchasers. Hence, generators may be responsible for a certain
percentage (say 60%) of the TUOS charge divided among all generators
uniformly, while the remaining percentage is shared uniformly among
distributors/bulk purchasers. In Nigeria, the postage stamp method is
used to apply uniform TUOS charges only to
distributors/retailers.
Wheeling charge method: this method is based mainly on the transactions between two users and
is commonly used in bilateral electricity trade between two countries.
It involves the determination of a fictional transmission path, by
parties to a power sale transaction, in which the electric flow will
pass from the point of injection by the seller to the point of
delivery by the buyer. The charge is computed as a fraction of the
cost of the network path (lines and associated infrastructure) where
the transaction “flows”. In a very simplified form of
applying this method, the regulator computes the cost of respective
lines in the network and the estimated total annual flow on these
lines. The wheeling charge is then simply expressed as:
Distance-based method: this transaction-based method considers not only the amount of energy
transmitted through the line but the length of each line used for any
transaction. In a very simplified form of applying this method, the
regulator develops a base case scenario in which it:
Identifies all transactions using the network;
Determines the fictional transmission path for each transaction;
Determines the transmission flow in MW per transaction per line;
Multiplies the transmission flow per transaction per line by the length of the line to get an MW-km product;
Sums all the MW-km products for all transactions using the line to arrive at a total MW-km base case amount.
Then, removing any particular transaction, the regulator repeats the
above process and calculates the resulting total MW-km amount. The
difference between the second sum and the first sum is the amount of
MW-km flow on the line allocated to the transaction removed. The
transmission charge is then calculated as:
Nodal pricing
In some liberalised or wholesale electricity markets, the cost
allocation methods described above are used to determine fixed charges
that supplement other charges known as variable network charges. The
variable network charges are implicit charges derived from the
differences in marginal prices among different nodes in the electricity
network. Such differences exist in a market system as a result of losses
in the transmission system. Nodal prices are used to send signals to
network users on more efficient locations to site new generation or
load.
When electricity is transmitted from one point (node) to another, some
of the electrical power is lost as heat. The amount of power lost
depends on the distance of the generator to the load (the farther the
distance the more power is lost), the resistance of the transmission
lines, the environmental conditions, and the amount of power flowing
through a line at any particular point among other factors.
Using a model that calculates the impact of each user on the
transmission losses, each generator’s marginal costs, the demand
level at each node, and active transmission constraints, the regulator
assigns loss factors or node factors to various nodes in the system.
These factors are used to determine the electricity prices at each node.
The loss factor estimates the losses associated with injecting or
receiving an additional unit of electricity at any particular node. It
is also used to calculate the marginal cost of meeting electricity
demand at any node. For instance, if the loss factor at a particular
bulk supply node is 5% and a generator has a contract to deliver 100 MW
to that node within an hour, the generator must supply 105 MW to meet
its delivery contract to the node and the associated losses. Thus, if
there is a bulk supply connected to the generator’s node, the
marginal cost of meeting demand at the generator’s node will be
less than the marginal cost of meeting demand at the other bulk supply
node — there will be fewer or insignificant losses at
the generator’s node.
The differences between the prices of electricity between nodes are
allocated to the transmission utility as variable network charges.
Because these charges are variable and depend on a lot of contingencies,
they may be insufficient to recover the investment and operation costs
of the transmission utility. Hence, the regulator uses the cost
allocation methods previously described to determine supplementary
charges for the transmission utility.
In countries that do not use wholesale electricity prices, and
electricity generation prices are not determined by market forces, the
regulator may use transmission loss or congestion factors as an
alternative to achieve the same locational signal objective associated
with the use of nodal prices. With this practice, the generator bears
the cost of the extra units of electricity needed to cover the
transmission losses related to its generation. This practice is used
with the fixed cost allocation methods (supplementary charges) discussed
previously.
Designing the transmission tariff structure
After determining the method for allocating the costs among network
users as fixed or supplementary charges, the regulator finally
determines the format of the tariff. The regulator’s decision on
tariff structure may affect the private investment decisions and
deserves careful consideration. The regulator may decide to design the
transmission tariff as a lump sum, a volumetric energy charge ($/MWh), a
volumetric capacity charge ($/MW), or an hourly availability charge
($/hour of t-line availability). As a lump sum charge, the regulator
designs the TUOS cost allocated to a user as a one-off charge to be paid
by the user annually. The regulator may also divide this lump sum into
fixed monthly charges.
As an energy charge, the recovery of cost by the transmission utility
depends on the actual energy generated or consumed by the network user.
This may expose the transmission utility to losses since it has no
control over the behaviour of other network users. For instance, with
the increase in behind-the-meter installations, an energy charge for
transmission means that network users whose demand may have justified
transmission investments will avoid payments for such transmission
infrastructure in their end-use tariffs. This may affect the transmission utility’s ability to pay costs associated with private investments in the
transmission network. There may also be fairness issues associated with
the other tariff formats which are structured as capacity charges or
availability charges. Some network users may feel that they are paying
more than other users if their electricity production or consumption
rates are considered.
Some regulators balance these considerations by using a mix of energy
charges and capacity or availability charges. The suitable tariff format
or a mix of formats adopted by the regulator depends on the nature of
the market, the business models for private investment in transmission
allowed in the market, and the regulatory goals. Nonetheless, the tariff
format should ensure that the transmission utility recovers its cost
without compromising on principles of fairness, non-discrimination, and
transparency.
Introduction
This handbook has largely focused on the funding of domestic
transmission infrastructure. Another important topic is the features of
cross-border transmission infrastructure development and the complexity
of funding such regional projects.
Most of the risk allocation factors described in this handbook apply to
cross-border interconnection. Although they have significant benefits,
cross-border projects can also present additional implementation
challenges when jointly undertaken by host governments and/or utilities.
They may be constrained by varying policy, legislation, governance
requirements, funding restrictions, restrictions or conditions to
project company foreign or local shareholding, borrowing restrictions,
and the like. Private sector participation is sometimes a viable option
for reducing or mitigating such risks.
What Are Cross-border Interconnection Projects?
A cross-border project is transmission infrastructure that spans two
or more neighbouring countries, creating a transmission
interconnection between the electricity networks of the respective
countries. Cross-border projects can provide transmission services to
domestic transmission consumers and dedicated transmission capacity to
power generation projects, but importantly enable the regional
development of transmission infrastructure. Where cross-border
transmission lines exist, countries with constrained funding and
unstable or underdeveloped transmission infrastructure can lean on
neighbouring countries to trade in electricity conveyed over that
cross-border transmission infrastructure. Cross-border
interconnectors aim to provide countries with an increased supply of
electricity to meet growing demand where the generation capacity in a
neighbouring country is strong. Other advantages include assisting a
national grid in saving costs from having reserve capacity and
stabilising the national grid.
Cross-border projects are not new to the African continent. There are
many successful interconnector projects. These include:
The CLSG transmission line in West Africa, which involves the
construction of a 1,303 km transmission line allowing power
exports from Côte d’Ivoire to Liberia, Sierra Leone,
and Guinea
The 2,000 km 225kV connections that serve connecting points in
Mali, Mauritania, and Senegal
The 225kV Ghana - Cote d’Ivoire interconnection
The 161kV Togo - Benin interconnection
The MOTRACO transmission project (case study below), a project
with multiple interconnectors across the SADC region set up to
facilitate power trading in the SAAP.
Benefits of Cross-border Projects
The benefits of undertaking a cross-border transmission project
interconnecting neighbouring countries are numerous, some of which
are:
interconnecting neighbouring countries’ power systems;
increasing regional supply across a regional network;
increasing grid stability;
improving system control;
creating reliable and accessible power supply; and
facilitating electricity trading amongst members of power pools.
Hurdles to the Development of Cross-border Projects
Despite the benefits, there are many challenges and constraints to
developing cross-border transmission infrastructure, in particular the
raising of funding and facilitation of private sector participation.
We have identified a few of these hurdles below.
Joint development and joint ownership models
Transmission interconnection projects can be constructed and developed
individually by each respective country, or undertaken jointly by all
the countries acquiring the transmission asset. This has been the
typical approach taken by some cross-border projects on the African
continent. The asset itself is therefore owned individually by
each country in respect of those portions within the respective country,
or jointly by all countries over which the asset is developed. The joint
development aspect and joint fundraising is a nuance that creates
complexity with cross-border transmission projects.
The starting point for cross-border transactions is an
Inter-Governmental Memorandum of Understanding. This sets the governance
model for development. This will usually define whether a JV or project
implementing unit is created for the project preparation work. It should
be noted that there is considerable funding available to fund
preparation studies for regional integration projects from multilateral
donors.
Funding constraints
Challenges in raising funding for cross-border projects can arise for many reasons, relevant to one or more of
the countries, being the limited ability of the utility or government:
to borrow due to existing financial
constraints;
to provide the appropriate collateral
for the funding; and
to "guarantee" to any funder any consistent revenue flows
from the use of transmission infrastructure.
Project finance fundraising is therefore challenging unless the
transmission utility or host government agrees to pay a regular
availability fee or subsidise the tariff where demand across the line
and commensurate revenues is not sufficient to meet the repayment of the
debt. In short, project finance funders would not likely take the
“demand risk” as detailed in chapter 11. Common Risks.
Where host governments undertake regional transmission development to
meet particular government objectives, for example, to enter into
regional electricity power trading, or to become an active participant
within a power pool, host governments can consider any form of subsidy
or guarantee offered by it as being a critical upfront cost to achieve
such goals. Once the goal is achieved and the transmission network
improves, the initial funding challenge is progressively lessened as
electrification rates increase and demand risk reduces. However,
the initial challenge of how the infrastructure is funded remains.
Development Finance Institutions (DFI) provide the government with excellent
sources of capital for funding cross-border transmission lines. Provided
the business case and the project preparation is well-conceived,
DFIs with an agenda to promote regional trade are aggressively
pursuing these types of projects. One example of these is the funding
for the Ethiopia-Kenya interconnector and the latest funding for the
Temane interconnector in Mozambique, which has a business case motivated
by regional trade.
Varying Domestic Regulatory Frameworks
As described earlier in this handbook, each country has a unique
regulatory framework governing the transmission sector, including the
national electricity legislation, the licensing regime, and the grid
code. In most instances, there also exists a PPP or other
procurement regime for the competitive, open, and transparent process to
award a concession, or an IPT, or any other private-sector party to
undertake the development and operation of transmission
infrastructure.
Where there are two or more countries, a multiplicity of legal and
regulatory regimes may govern the development of the interconnection
infrastructure, which may create delays at the development stage.
For example, if three countries are entering into a joint
development agreement to construct interconnection facilities across a
region, that JV company will likely want to appoint a single EPC
contractor for the construction of the entire transmission corridor.
The granting of rights to the JV company, where that company is
incorporated, how it is run and how it is empowered, will all need to be
agreed upon. This may lead to complex negotiations to take account
of regulatory differences across countries for matters from the procuring
the EPC contractor to the staffing of the JV company itself. Negotiating and agreeing to all of these details is typically not a quick
process.
It should be noted that for instance the cross-border interconnections
are regarded as an unregulated business in terms of the local
regulations. An example of this is the South African treatment of these
interconnectors and the trade that takes place. However, these
interconnectors will remain subject to other legislation such as ESIA
and tax legislation.
Competing electricity regulators
Power pools in Africa have generally developed their own grid codes,
operational standards, and have standardised cross-border electricity
trading agreements, and transmission use of system and connection agreements. There is often a regional regulator
who provides a monitoring and oversight role in respect of compliance
with the suite of codes, standards and agreements developed by the power
pool.
Whilst a domestic regulator’s legal authority and mandate emanate
from domestic law, regional regulators typically have a mandate through
contract, for example where power pool members agree contractually to
abide by the membership rules of the power pool, including decisions by
the regional regulator. However, in countries where there may be
political or economic barriers where domestic policy decisions favour
domestic generation over imports, the domestic law may well trump the
regional rules. It is therefore imperative for the success of a
cross-border project that the relevant policymakers fully support the project,
see chapter 9. Planning and project preparation.
Case Study — The MOTRACO transmission project: an interesting hybrid model
The Mozambique Transmission Company (MOTRACO) was founded in 1998 as a
joint venture between the government utilities of Mozambique
(Electricidade de Moçambique — EDM), South Africa (Eskom)
and Eswatini (Swaziland Electricity Board, now Eswatini Electricity
Company — EEC). MOTRACO is a joint venture company that has as its
aim the efficient provision of electricity to businesses in all three
countries. It should be noted that government support in the form of
assisting with transmission licensing and regulation in the three
countries at a time when only state utilities had transmission licenses
was critical to ensure MOTRACO could become an IPT company (although
state-owned).
The “anchor” customer was the Mozal aluminium smelter
plant, 20 km outside Maputo. The aluminium plant had significant
electricity demands and was willing to pay MOTRACO a wheeling charge for
the reliable energy it received. The aluminium plant paid the cost of
electricity purchased from ESKOM. The fixed portion of the wheeling
charges relating to the energy transmission covered debt service and
operational expenditure of MOTRACO. The management, maintenance, and
control of the MOTRACO network were outsourced to Eskom.
EDM and EEC also have independent wheeling contracts with MOTRACO. This
allows the utilities to participate in SAPP and trade power in both directions (i.e. import power from the
market when supply is constrained and export to the market when
surpluses are available).
The initial phase of the investment, worth US$ 93 million, was
completed in mid-2000. MIGA issued guarantees to Eskom to cover loan
guarantees to the European Investment Bank and the Japan Bank of
International Cooperation for their investments in MOTRACO to cover the
investment against the risks of expropriation, war and civil
disturbance. The French development agency AFD provided additional
financing for later stages.
The deal has subsequently grown to link to the wider Southern African
Power Pool. The transmission interconnection benefited both Mozambique
and Eswatini by improving the quality of electricity distributed to the
population in those countries.
Of note was the fact that there was an “anchor” customer,
thereby reducing “demand risk” (see Chapter 11. Common Risks for a further explanation of demand risk). It further benefited from a guarantee from Eskom. At the time of
granting this guarantee, Eskom had a stand-alone investment-grade credit
rating. The MIGA cover was taken to protect the Eskom balance sheet
against political risk.
The project provided the industrial company Mozal with a reliable
supply of electricity to meet its increased production and
industrialisation of Mozambique post-civil war, at the same time as
strengthening the energy supply networks of Eswatini and Mozambique. For
EEC and EDM, the transmission infrastructure helped lower the cost of
energy and increase its availability, as well as to increase the
reliability and security of interconnected systems in the region. By
becoming active trading partners in the SAPP, both countries benefited
from low-cost power purchase in the SAPP market.
Figure 13.1 MOTRACO transmission project
Other examples of successful cross-border projects
Many successful cross-border projects have occurred outside Africa as
well.
Several cross-border lines exist across varying European Union
countries (including more than 80 cross-border interconnections between
the EU and neighbouring countries). The further development of
cross-border transmission infrastructure is designed to meet the
EU's external policy objectives, including energy transition (and
the integration of renewable energy), security of supply as well as
regional and local socio-economic welfare, economic cooperation, peace
and solidarity. There are many political and economic reasons for a
country to cooperate with neighbouring countries and benefit from
existing and future interconnectors.
Some other international cross-border transmission projects include:
Paraguay-Brazil (Itaipu 12,600 MW Hydro) and Paraguay-Argentina
(Yacyreta 3,100 MW Hydro); Paraguay surrendered operating
control of the hydro plants to Brazil and Argentina,
respectively.
Uruguay and Argentina agreed to share the energy generated from
the Salto Grande hydro plant (1,890 MW), with Uruguay consuming
50% of the energy and Argentina consuming 50% of the energy.
The CIEN lines built by ENDESA connecting Argentina and Brazil
(back-to-back interconnection) includes one line (1000 MW) with
a firm contract and another (also 1000 MW), which is a
merchant.
Salta cross-border interconnection between Argentina and Chile
built by AES (private company) to supply power to copper mines
(in the north part of Chile). Salta thermal plant (640 MW)
in Argentina is dedicated to supplying the mines in Chile.
The SIEPAC (230kV line) synchronously interconnects six
countries in Central America and allows up to 300 MW of trade
within a regional electricity market.
Two back-to-back (one 220kV and the other 400/500kV)
interconnections between Georgia and Turkey; the latter is a
merchant line.
Private Sector Participation in Cross-border Projects
Private sector participation in cross-border projects has similar
benefits to private funding of domestic transmission projects. These
benefits include an increased mix of financing options and proper risk
allocation and cost recovery methods. However, private participation in
cross-border projects has its own complexities. Nonetheless, provided
that the private sector developer(s) is empowered by the various
governments, it can overcome some of the hurdles specific to the
government-funded cross-border projects.
In this section, we will summarise some of the possible private-sector
structures that could apply to cross-border projects.
IPT Models
The concept of an independent transmission project, as described in chapter 5. Independent Power Transmission (IPT) Projects above, can also apply to cross-border transmission infrastructure.
In the earlier discussion, it was assumed a single local
government or country defines the structure. For a cross-border project,
the complexity of resolving the requirements for private participation
extends to multiple governments. An example of this will be land
acquisition. This will need to be agreed upon with multiple governments
and the leasing structure for the rights-of-way will need to ensure that
the long term titles are valid across all jurisdictions.
In short, all of the considerations that are required for a
single-country project that need to be addressed and resolved are
multiplied in cross-border transactions (e.g. how is political risk
allocated between two countries if the event starts in one country but
spills across to another).
The key risk to be addressed to allow IPT financing to take place is
that of payment risk. An analysis will be required of the various users
of the infrastructure. The tariff applicable to all jurisdictions
would need to be considered. The payment risk for the transmission use
of system charges or the capacity charges will also need to be addressed
and this will get especially complex in default scenarios. One of
the ways this can be resolved is for all of the government utilities to
adopt joint and several liabilities with a defaulting utility. This may be possible although it will
require complex inter-government negotiations.
Industrial demand-driven model
As seen from the MOTRACO example above, a public sector project can be
done with an “anchor” industrial offtaker. This
addresses one of the key risks as regards demand and payment risk.
However, the need for an umbrella guarantee from one of the parties may
still be required, depending on the creditworthiness of the other
offtakers and the reliability of the industrial user.
Whilst this is not necessarily a privately funded model, the existence
of a private-sector party in the overall structure will allow for
different types of lenders to fund the cross-border infrastructure.
Whereas previously only concessional funding may have been
available from donors, the existence of an industrial offtaker allows
the entry of commercial banks and DFIs, who can provide loans at
commercial rates. The advantage of a model that is more linked to
an industrial offtaker is the reduction in the impact on the respective
governments’ balance sheets.
Merchant power lines
In some instances where there is an operating regional market such as
the SAPP, it may be possible to consider merchant transmission lines. We
refer the reader to the earlier discussion on challenges in implementing
a merchant transmission line in chapter 7. Other Private Funding Structures. These can work across borders. If,
for example, country A has abundant resources that enable it to generate
plentiful and cheap electricity but neighbouring country B has no such
resources and is reliant on importing fuel to burn for expensive
electricity, it is conceivable that a private sector developer could
develop, finance and build a transmission line that is used to connect
one country’s grid to a particular plant (or simply to the other
country’s grid). The project company in this instance would
earn revenues from “wheeling” or use-of-system charges
payable by country B. Similar cross-border merchant lines have
been delivered in the US and Australia, for example (across state
borders).
Private sector example
An interesting example of a cross-border project done by a private
company is the Zambia-DRC interconnector developed by CEC in Zambia. As
a private whole-of-the-grid in the Copperbelt region licensee, CEC was
able to develop and implement the cross-border transmission line. The
line is used by SAPP members to trade power between SNEL in the DRC and
other members. CEC benefits from wheeling charges as well as trading of
energy across the line.
Summary of Key Points
Cross-border projects are transmission infrastructure projects that
span over two or more neighbouring countries, creating a transmission
interconnection between the electricity networks of the respective
countries.
Cross-border projects are not new to the African continent. There are
many successful interconnector projects both in Africa and
globally.
The benefits of undertaking a cross-border transmission project
interconnecting neighbouring countries are numerous, including grid
stability, system control, and trade benefits.
Despite the benefits, there are also many challenges and constraints
to developing cross-border transmission infrastructure, in particular
the raising of funding and facilitation of private sector
participation.
The joint development aspect and joint fundraising of multiple
countries is a nuance that creates complexity with cross-border
transmission projects.
Challenges in raising funding for cross-border projects can arise due
to existing utility or government financial constraints.
Project finance fundraising is challenging for cross-border projects as project finance funders would not be likely to take the
“demand risk”.
Development Finance Institutions provide the government with
excellent sources of capital for funding cross-border transmission
lines, provided the business case and the project preparation are
well-conceived.
Where there are two or more countries, a multiplicity of legal and
regulatory regimes may govern the development and procurement of the
interconnection infrastructure, which may create complexity and delays
at the development stage of the project.
Whilst a domestic regulator’s legal authority and mandate
emanate from domestic law, regional regulators typically have a
mandate through contract, for example, where power pool members agree
contractually to abide by the membership rules of the power pool,
including decisions by the regional regulator.
When considering the complexity and cost of a regional cross-border
interconnection project to host governments and utilities, it would
appear to be an area of transmission development that may be well
suited to private sector involvement.
Possible private-sector structures that could apply to cross-border
projects are:
IPT models;
industrial offtake model; and
merchant power lines.
Acronyms
A
AfDB — African Development Bank
B
BOO — Build Own Operate
BOOT — Build Own Operate Transfer
BOT — Build Operate Transfer
C
CAPEX — Capital Expenditure
COD — Commercial Operation Date
D
DFI — Development Finance Institutions
E
EPC — Engineering, Procurement and Construction
ECA — Export Credit Agencies
EIA — Environmental Impact Assessment
ESIA — Environmental and Social Impact Assessment
G
GSA — Government Service/Support Agreement
I
IFC — International Finance Corporation
IPP — Independent Power Producer
IRP — Integrated Resource Plan
IPT — Independent Power Transmission
K
KPI — Key Performance Indicators
kWh – Kilowatt Hour
M
MWh – Megawatt Hour
MDB — Multilateral Development Banks
MoF — Ministry of Finance
MTS — Main Transmission Substation
O
OECD — Organisation for Economic Co-operation and
Development
OEM — Original Equipment Manufacturer
O&M — Operating and Maintenance
OPEX — Operating Expense
P
PCOA – Put and Call Option Agreement
PCG — Partial Credit Guarantee
PRG — Partial Risk Guarantee
PPA — Power Purchase Agreement
PRI — Political Risk Insurance
PPF — Project Preparation Funds or Facilities
PPP — Public-Private Partnerships
R
RAB — Regulated Asset Base
RfP — Request for Proposal
RfQ — Request for Qualification
ROR — Rate of Return
S
SAPP — Southern African Power Pool
SADC — Southern African Development Community
SPV — Special Purpose Vehicle
SSA — Sub-Saharan Africa
T
TDP — Transmission Development Plan
TSA — Transmission Service Agreement
TSO — Transmission System Operator
Glossary
A
Annual Revenue Requirement — the total revenue to be collected in a given year through the
transmission of electricity over the transmission infrastructure,
including associated technical losses, to compensate the transmission
operating company for all expenditure incurred in the same year and
provide the basis for sound economic operation of the
infrastructure.
B
Balance Sheet Financing — the financing of a project which is provided in full by a
sponsor.
Bankable — a project or contract is said to be “bankable” if it
comprises a level of risk allocation which would be generally acceptable
to lenders.
Baseload Power or Capacity — generating capacity within a national or regional grid network
that the offtaker or grid operator intends to dispatch or utilise
continuously.
C
Concession — a right to develop, construct, operate and maintain an infrastructure
project and to earn the revenues generated by the project.
Concession Agreement — an agreement that grants a concession over a transmission system or a
part of a transmission system.
Concessionaire — the holder of a concession.
Corporate Finance — used to distinguish Project Finance (see below). Corporate
finance implies that a borrower utilises its existing balance sheet
strength and operational cash flows to borrow. Lenders assess the
creditworthiness of the corporate entity itself. This includes an
assessment of its current indebtedness, its capital structure and the
business plan of the corporate entity.
Commercial Operation Date (COD) — a key milestone date defined in the agreement when the
transmission infrastructure commences commercial operation after all
testing and commissioning have been completed.
D
Deemed Energy Payments — payments made concerning deemed generation.
Deemed Generation/Energy — the electricity that a power plant would have been able to
generate, but for the occurrence of an event or circumstance for which
the offtaker bears the risk.
Developer — see Sponsor.
Development Finance Institutions (DFI) — financial institutions with a mandate to finance projects that achieve
development outcomes. Examples include the World Bank, AfDB, OPIC, FMO,
DEG, CDC, DBSA and Proparco.
E
Engineering, Procurement and Construction (EPC) contract — one or more contracts to be entered into between the EPC
contractor and the project company for the purpose of setting out terms
and conditions for the design, engineering, procurement of materials and
equipment, the construction and commissioning of the power plant.
EPC + F — in addition to the Engineering, Procurement and Construction (EPC) definition, the EPC+F is a project financing mechanism in which
the EPC contractor also arranges financing for the project, through
tie-ups with financing institutions. It is useful when EPC contractors
have better access to low-cost financing, including EXIM
financing.
Environmental and Social Impact Assessment (ESIA) — a process of evaluating the environmental and social impacts of a
proposed project, evaluating alternatives and designing appropriate
mitigation, management and monitoring measures.
Equity — money invested by the sponsors in the project that is not
borrowed by the project company. The term "equity" may
sometimes be used to include shareholder subordinated debt (which is
finance made available to the project company by the sponsors or
shareholders of the project company, which is subordinated to debt made
available by the lenders).
Export Credit Agencies (ECA) — public agencies and entities that provide government-backed
loans, guarantees and insurance to corporations from their home country
that seek to do business overseas in developing markets.
F
Force Majeure Event — an event beyond the control of the affected party that prevents
it from performing one or more of its obligations under the relevant
contract. Events constituting force majeure are generally further
classified into political force majeure events and non-political force
majeure events, with different financial and contractual consequences to
the contracting parties. Natural force majeure events fall within the
latter category.
Financial Close — occurs when all conditions precedent in a signed loan agreement have
been met or waivered, making the funds available for drawdown.
Finance documents — the agreements required to finance the relevant transmission
infrastructure project under which the project company borrows (and then
owes financial obligations to) a series of lending institutions —
be they banks or development finance institutions or export credit
agencies. The facility agreement is typically one of the main finance
documents which is an agreement that sets out the terms and conditions
on which the lenders make a loan available to the project company.
G
Government Support Agreement — an agreement entered into by a host country and a project company
established to undertake an infrastructure project or hold a concession
to provide certain identified types of support to the project company in
respect of the project or concession.
Government Concession and Support Agreement — an agreement between the host government and the project company,
under which the host government agrees to certain undertakings
concerning the project. This agreement typically goes beyond the
customary provisions of an Implementation Agreement and may include an
explicit guarantee of the performance obligations of a governmental
entity, such as an offtaker or fuel supplier.
Grid — a system of high tension cables by which electrical power is
distributed throughout a region.
H
Host Country — the country in which a project, concession, or part thereof is located.
I
Independent Power Producer (IPP) — a special purpose company established for the sole purpose of
developing, financing, constructing, owning, operating and maintaining a
power plant.
Institutional Lender — a regulated financial institution engaged in lending.
Integrated Resource Plan (IRP) — is an electricity infrastructure development plan based on least-cost
electricity supply and demand balance, taking into account several
considerations such as the security of supply, ability to reduce/shift
the demand and the impact on the environment.
Interconnection — the linkage of transmission or distribution lines between the
offtaker (utility) and the power plant, enabling evacuation of the
energy generated.
Investor — see Sponsor.
Independent Power Transmission (IPT) — the construction and financing by a private sector investor of a
single transmission line or a package of transmission lines and/or
associated transmission infrastructure including substations. These are
independently owned but typically connected with the wider electricity
network.
J
Joint Venture (JV) — a joint venture is a commercial enterprise undertaken jointly by
two or more parties that otherwise retain their distinct identities.
These can be conducted either by way of incorporating a special purpose
vehicle (called the JV company) or by way of contract alone (in which case it is called an
“unincorporated” joint venture).
K
Key Performance Indicators (KPIs) — set of performance indicators used to evaluate the performance of
a project or system.
Kilowatt Hour (kWh) — a measurement of energy that is equal to 1,000 watts of
electricity being generated or consumed continuously for one hour.
Kilovolt (kV) — a unit of potential equal to 1,000 volts.
L
Lenders — the providers of loan financing to the project company.
M
Megawatt (MW) — a measurement of power meaning 1,000,000 watts.
Multilateral Development Banks (MDBs) — an institution, formed, owned and controlled by its member
countries, that provides financing and advisory development services.
Examples include the World Bank (IBRD and IDA), AfDB, and MIGA.
N
New York Convention — the Convention on the Recognition and Enforcement of Foreign
Arbitral Awards (also known as the New York Convention) allows for the
enforcement by a contracting state of arbitration awards issued by
another contracting state, subject to limited defences.
Non-Recourse Financing — financing that will be repaid solely through the cash flow
proceeds of a project, structured as a special-purpose vehicle. The
obligations of the shareholders in the special-purpose vehicle are
usually limited to their obligation to contribute capital and, in some
cases, to provide other limited and well-defined support to the
special-purpose vehicle.
O
Offtaker — the party to a PPA whose obligation is to purchase the capacity
made available and the electricity generated by the power plant, subject
to the terms and conditions of the PPA. Also referred to as the
Buyer.
Operating and Maintenance (O&M) Agreement — the agreement between the project company and a plant facilities
operator under which the operator operates and maintains the power plant
and associated facilities.
P
Partial Credit Guarantee (PCG) — a guarantee that covers interest and principal defaults, up to a
pre-agreed amount — expressed either as a fixed sum or as a
percentage of the credit balance. See Chapter 2 on Funding Options and
Constraints.
Partial Risk Guarantee (PRG) — a guarantee specifically structured to address targeted risks and can
be time-bound or event-bound. See Chapter 2 on Funding Options and Constraints.
Power Purchase Agreement (PPA) — a medium-to-long-term contract that governs the production, sale
and purchase of electrical capacity and energy. Also referred to as an
"offtake" agreement.
Political Risk Insurance (PRI)— offers coverage to mitigate and manage risks arising from the
adverse action, or inactions, of governments that go against contractual
obligations. PRI can be provided by both public and private
insurers.
Privatisation — also called divestiture, in the context of this handbook, relates
to where full ownership of the transmission infrastructure is
transferred to a private-sector party. Privatisation may occur on a
single transmission corridor, by region or even in respect of the entire
transmission system operation in a country.
Project Company — a special purpose company established to undertake an infrastructure
project. Also referred to as a Special Purpose Vehicle (SPV), a corporate entity established specifically to pursue a specific
project and is prohibited from undertaking any activity beyond the
project in question. For this handbook, the term Project Company is used.
Project Documents — key project and finance documents that would typically be
required in transmission projects.
Project Finance — see Non-Recourse Financing.
Project Preparation Funds or Facilities (PPF) — donors/fundsdesigned to provide funding for the project preparation of transmission
lines. Some have specific objectives such as the introduction of the PPP
model or to help promote regional integration while others aim at
encouraging projects that help meet climate change targets.
Public-Private Partnerships (PPP) — arrangements between the public and private sectors whereby a
service or piece of infrastructure that is ordinarily provided by the
public sector is provided by the private sector, with clear agreement on
the allocation of associated risks and responsibilities.
R
Regulated or Regulatory Asset Base — this is a system of long-term tariff design aimed primarily at
encouraging investment in the expansion and modernisation of
infrastructure. It looks at the overall value of regulated assets (e.g.
a national transmission grid) and uses that to create a methodology for
paying a private operator to run the relevant assets.
Regulation by Contract — regulation by contract is a form of governing private contracts
with utilities that uses no separate regulatory agency, where the public
sector owner of the asset monitors the performance of the (private)
operator and sets the relevant tariff and revenue arrangements. A
contract typically defines the relationship between the asset owner and
the service provider.
Regulator — the authority that is responsible for ensuring efficiency,
transparency, and fairness in the management of the electricity sector.
An independent regulator is generally established by the legal
framework that governs the electricity sector as a legal entity that is
separate from the government and is governed by a board of commissioners
with fixed terms who can only be removed for cause, as defined in the
legislation that established the regulator. Regulators issue,
modify, and enforce licenses (including transmission licenses) and
establish and implement price controls for network businesses and, in
some cases, generation businesses.
Request for Proposal (RfP) — a solicited invitation from the procuring entity to potential
bidders to submit a proposal to develop a power project.
Request for Qualification (RfQ) — a solicited invitation from the procuring entity to invite potential
bidders to provide qualification credentials for the development of a
power plant.
Reverse Auction — a process where there is a single buyer and many suppliers. The
buyer indicates its requirements, and suppliers progressively bid
downwards. The lowest bidder wins the right to supply. This is opposite
to a regular auction that involves a single seller and many
buyers.
S
Sponsor — a commercial entity active in developing and investing in power
projects. Typically, it is a shareholder of the project company. Also
known as the investor or developer.
T
TransCo — a state-owned utility that owns a transmission network.
Transmission Development Plan (TDP) — a consultative process to identify viable, economical, and
environmentally feasible projects. The process evaluates and compares
options and alternatives based not only on technical efficiency and
cost, but also on their environmental, social, regulatory, and political
impacts.
Transmission Service Agreement (TSA) — an agreement concluded between the relevant IPT and the grid
operator that entitles the IPT, as a network user, to use the grid and
transmission systems of the relevant country.
Transmission System Operator (TSO) — entity entrusted with transporting energy on a national or
regional level, either directly or through instructions issued to others who operate as
agents of the TSO.
W
Wayleaves — rights-of-way granted by a landowner, generally in exchange for
payment and typically for purposes such as the erection of transmission
lines, telecommunications infrastructure or for the laying of
pipelines.
