By Ryan Ketchum and Chris Flavin. Ryan is a partner at Hunton Andrews Kurth LLP. Chris is Gridworks’ Head of Business Development.
In a series of articles this year, Chris and Ryan have looked at ways to increase private investment in Africa’s electricity transmission networks. The continent’s energy transition depends not only on generating power, but on moving it into homes and businesses. However, the shortage of transmission infrastructure is a key impediment to connecting consumers to electricity.
Africa has the lowest global levels of transmission lines and faces a multi-billion dollar shortfall in funding for network infrastructure. Energy access and economic growth will struggle without higher investment in large-scale transmission infrastructure.
This is the final article in our series. Previous articles have:
- discussed the need to increase the level of investment in electricity transmission systems to reduce costs, facilitate the transition to energy systems that are less carbon intensive, increase system stability, and reduce the level of generation reserves that are required to maintain system stability;
- identified four business models that can be used to unlock new sources of capital by facilitating private investment in transmission infrastructure (whole of network concessions, independent transmission projects (“ITPs”), privatisations, and merchant lines);
- described ITPs in more detail; and
- introduced whole of network concessions and discussed some of the structural features of those concessions and the two main forms of economic regulation that are used to establish rates.
This article focuses on several issues that are critical to the bankability of concession transactions. Those issues include how buy-out payments are calculated, some currency-related considerations, and the allocation of risks among the parties to the transaction and consumers. There are few examples of privately funded transmission concessions on the continent of Africa at present, so this article draws from the general principles applied to this model when it has been used elsewhere in the world. Specific concessions will normally have targeted approaches to address a specific local environment.
In an earlier article in this series that describes how network utilities are regulated, we learned that:
- the component (RateBasey x WACCy) provides a utility with a return on its investment;
the depreciation component of a utility’s annual revenue requirement provides investors with the return of its investment;
- shorter depreciation periods increase rates over the short term by increasing the depreciation component of a utility’s annual revenue requirement but increase the overall returns paid by consumers because assets remain in the rate base for a longer period of time; and
- that many of the assets of a transmission utility have very long service lives and correspondingly long depreciation periods.
To use a simple example, let’s examine the following fact pattern. A state owned utility (the “grantor”) enters into a concession with a 20-year term. The concessionaire places a transformer with an acquisition cost of $1 million into service on the first day of the concession. The regulator requires the concessionaire to use straight-line depreciation and establishes a depreciation period of 30 years for the type of transformer placed into service by the concessionaire. At the end of the 20-year concession, how much of the initial $1 million acquisition cost has been recovered by the concessionaire?
To determine the answer, we first convert a depreciation period of 30 years into annual depreciation of 3.33% of the acquisition cost. By multiplying $1 million times 3.33%, we can determine that the concessionaire will recognize $33,333.33 in depreciation each year and include that amount in the depreciation component of the annual revenue requirement. Multiplying this number by 20 years gives us the answer, which is that the concessionaire will have recovered $666,666.67 of its $1 million investment over the 20-year term of the concession.
In this example, the concessionaire will not have recovered $333,333.33 of its investment by the end of the concession. The concessionaire will recover this remaining amount, which is the undepreciated value of the transformer, by receiving a payment from the grantor at the end of the term of the concession. This type of payment is referred to as a hand-back payment, a buy-out payment, or a buy-out price. We will refer to it as a buy-out payment.
The above example shows how depreciation is recognized in relation to one particular asset. Building on this example, one might conclude that the best way to calculate a buy-out price is by summing the undepreciated value of each asset that was placed into service by the concessionaire. There is, however, a much simpler method of arriving at the same answer. The regulated asset base (in a performance-based regulation system, or the rate base in a cost-of-service system) is itself the sum of all investments made, less the sum of all depreciation recognized. As a result, the buy-out price at the end of the term of a concession can simply be set to equal the regulated asset base as of the end of the last year of the concession.
A significant advantage of this approach is that it allows the regulatory accounting system established by the regulator to be used to establish both the rates and the buy-out payment. This alignment results in consistency between decisions by the regulator regarding the regulatory asset base and the amount of the buy-out payment.
In scenarios other than the expiration of the term, the buy-out payment could be calculated by applying a multiplier to the regulated asset base. In the case of a termination of the concession following an event of default by the concessionaire, the multiplier would be less than 1.0. It may be .8 or .85 or .9, for example. In the case of a termination of the concession following (i) an event of default by the grantor 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 would be greater than 1.0. In this case, it may be 1.1, 1.15, or 1.2, for example. These multipliers can be tailored to suit the objectives of the host country, the concessionaire, and the lenders to the concessionaire. The multipliers should provide a reasonable incentive for all parties to perform their obligations under the project agreements. They should not be viewed as, or sized in terms of, a penalty, which could be enforceable under the laws of many host countries.
Buy-out payments can be sizable. The amount of the buy-out price is directly correlated with the amount of investments made by the concessionaire during the term of the concession. One of the objectives of a concession is to incentivize the private sector to make the investments that are required to upgrade and expand a transmission system. As a result, if the concession is appropriately structured and successfully achieves that objective, then the investments made by the private sector will be sizable. So will the resulting buy-out payment.
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 country, the grantor, and the concessionaire may agree to extend the term of the concession before its expiration. If the term is extended, then the need to pay a buy-out payment will be delayed. Further extensions may indefinitely delay the need to pay a buy-out payment.
If a host country is not satisfied with the performance of a concessionaire, it may raise funds to pay the buy-out payment by awarding a new concession that requires the payment of an up-front concession fee that matches the amount of the buy-out payment. In the alternative, a host government in this position could re-capitalize the grantor by injecting equity into the grantor and causing the grantor to raise an appropriately sized amount of debt to fund the remaining portion of the buy-out payment. A grantor could raise that debt by issuing multiple series of bonds with tenors that correspond to the depreciation profile of the assets that constitute the regulated asset base, by borrowing from a syndicate of banks, or using a combination of these approaches.
With the limited exception of countries that use a foreign currency to conduct financial transactions within their own economy and other very limited circumstances, the rates that are paid by electricity consumers are denominated in the currency of the host country. In many emerging market countries, capital markets and the market for loans from local banks are not sufficiently liquid to fund the debt component of the regulatory asset base of a transmission utility. Where this is the case, rates will need to be adjusted for changes in foreign exchange rates regularly.
Often these adjustments are applied quarterly and may be implemented by the concessionaire based on a formula contained in the tariff guidelines without the need for the regulator to issue a decision each quarter confirming the calculations made by the concessionaire. The formula should be designed to escalate only those components of the annual revenue requirement that are denominated in a foreign currency. Those components may include the return on the regulated asset base and depreciation, in which case the regulated asset base may also be denominated in a foreign currency. The foreign currency in which those items are denominated would be the foreign currency in which the concessionaire’s loan obligations and equity contributions are denominated.
The operations and maintenance component and other components of the annual revenue requirement would be partially denominated in the same foreign currency and partially denominated in the currency of the host country. The percentage of those components that are denominated in the foreign currency would correspond to the percentage of the costs incurred that are denominated in the foreign currency. A large part of the operations and maintenance costs incurred by a transmission utility is for labor. As a result, a large part of the operations and maintenance component of the annual revenue requirement would usually also be denominated in the local currency.
An appropriate allocation of risks is essential to attracting investment in the form of both debt and equity. The risk matrix below describes how a range of risks might be allocated in a typical concession transaction.
View suggested Risk Allocation Matrix.