By Joseph Lam, Legal Director DLA Piper

Earlier this year, the Economic Community of West African States (ECOWAS) presented its updated Master Plan for Regional Power Generation and Transmission Infrastructure 2019–2033 (the Master Plan). The Master Plan is part of ECOWAS’s drive to develop the West Africa Power Pool (WAPP) – a cooperative power pooling mechanism for integrating national power system operations into a unified electricity market in the West African region. Like in the rest of sub-Saharan Africa, a vast proportion of the population in West Africa is without access to electricity despite the region’s ample natural resources.

The lack of reliable and affordable electricity has hindered economic development and job creation. Given the small size of the power markets in most of the ECOWAS countries, increasing regional integration can lower the average cost of supply through economies of scale. It can also promote diversification of electricity sources, including renewables, enhancing system reliability and grid stability. This will however require significant investment in a stable and interconnected transmission network with minimal transmission losses that can support load increase, more flexible cross-border trade flows and the intermittent output of renewable power sources.

The Master Plan has identified 28 priority transmission line projects with a total length of approximately 22,932 km at an estimated cost of USD10.48 billion. The majority of them are cross-border interconnectors although some are national projects with regional significance. In this article I will focus on interconnection infrastructure. Government ownership (including through public utilities) has been the dominant approach to financing interconnection projects in Africa. Poor financial health of national utility companies in general and fiscal constraints of most governments in the region limit their ability to invest, even in financially viable projects. Private

involvement in these projects could help ease the financing constraints and bring experience in project implementation and operation as well as better organizational and financial discipline.

This article will look at the possible models for private investment in transmission infrastructure in the region, identify some potential challenges and consider how they may be addressed.

Investment models

 In the context of cross-border interconnections, private investment may take the form of merchant investment or independent power transmission (IPT). Neither model has been adopted in Africa to date. Most interconnection projects in the world have used the merchant investment model. Under this model, the merchant investors build and operate a transmission line. The owner of the line sets the terms and conditions for its access and generates revenue based on the amount of energy flowing along the line and the price differences between the two ends of the line.

Access to merchant lines is usually proprietary rather than open to all transmission users. Many power utility companies in sub-Saharan Africa are vertically integrated, state-owned monopolies. In many cases, their tariffs are set at artificially low levels due to the income level of their customers and political considerations. The resulting lack of flexibility and dynamics in the relevant wholesale electricity markets could undermine the basis of the business case and revenue model for merchant investment which is closely linked to the projected price differentials between two markets.

Furthermore, viability of a merchant line often depends on its ability to maintain a monopolistic position to serve as a link between two markets based on proprietary access. This model does not seem consistent with the stated

aim for the West Africa Power Pool, which is, to develop an integrated unified electricity market.

Independent Power Transmission (IPT)

Another model is to finance, build and maintain the transmission line by way of independent power transmission

(IPT). The IPT model has been identified by the World Bank as the “business model best suited to the conditions in Africa. In essence, it involves the government (or the state-owned utility) tendering a long-term contract whereby the IPT (the winning bidder) will be responsible for building and operating a transmission line in exchange for

contractually defined payments dependent upon the availability of the line. IPT projects have been adopted in many countries, though mostly in the context of in-country transmission. Adopting the model for interconnection between countries is however likely to be more complex, not least due to the need to coordinate between the governments of the relevant countries.

In West Africa, the Côte d’Ivoire-Liberia-Sierra Leone-Guinea (CLSG) interconnection project may point to a way forward. This USD508.2 million project involves the construction of a high voltage (225 kV) transmission line of over 1,300 km and associated substations connecting the four participating countries’ energy systems into the

WAPP. The project is implemented through a regional transmission company (TRANSCO CLSG) which is responsible for the financing, construction, ownership and operation of the project. TRANSCO CLSG is a special purpose

vehicle (SPV) owned equally by the national utilities of the CLSG countries.

To encourage its usage, the CLSG transmission line will have an open access policy. Power purchase agreements have been signed between Côte d’Ivoire’s national utility and those of the other three countries. Each of them has

entered into a transmission service agreement with TRANSCO CLSG. The transmission tariff is set using the postage-stamp methodology  so that transmission costs are effectively charged to the power purchasers based on their relative shares of the trade through the transmission line. To mitigate against the risk of funding shortfall

due to low trading volumes, the shareholders of TRANSCO CLSG undertake to pay for any shortfall from trading revenue.

This pricing methodology both ensures cost recovery and facilitates trade through the transmission line. The CLSG project is currently under construction and is expected to be commissioned in late 2019 or early 2020. While the CLSG project structure does not involve any private ownership of the project company, it is conceivable that a similar structure may be adopted to implement the IPT model, for example by replacing government-owned shareholders of the transmission SPV with private sector project sponsors.

This was in part the structure adopted by the Central American Electricity Interconnection System (SIEPAC) which had been taken into account in the design of the CLSG project.4 In SIEPAC, the transmission company, EPR, owns the 1,793 km interconnector (230 kV) which links the power grids of six Central American countries. EPR is owned

by eight national utilities or transmission companies together with a private company (ENDESA of Spain) which is responsible for managing EPR. During the project design stage, the option of relying entirely on private sector investment was considered. However, it was decided that there may not be sufficient interest from the private sector for such structure due to the perceived project risks and natural monopoly nature of transmission.

However, there seems no reason why, through proper risk management and with adequate financial incentives, such a structure cannot be adopted with entirely private ownership. The challenges faced by the power sector in sub-Saharan Africa are well documented. There are two challenges in particular to highlight in the context of

introducing private investment in interconnection projects, especially IPTs: the regulatory framework and financial viability.

Regulatory Framework

 As reported in the Master Plan, in most of the countries in West Africa, the electricity sector remains vertically integrated with monopoly networks. Although full-unbundling is not a necessary pre-condition for IPT, existing legislation and regulation will need to reviewed to enable the IPT to operate alongside the national utility. The grid code will need to be established or revised to provide operating procedures and principles. In the context of an interconnection project, this will need to be done for each country it connects and could be cumbersome and result in a long development lead time.

This issue is highlighted in the ongoing North Core Interconnector Project (a 330 kV transmission line connecting Nigeria, Niger, Benin and Burkina Faso). According to the Master Plan, the SPV structure adopted in the CLSG project had originally been envisaged also for the North Core project but was not adopted in the end in view of the considerable delay that necessary adjustments to the national legal frameworks would cause.

Financial Viability

 The CLSG project above has provided an example of how transmission tariffs may be set to meet any minimum revenue requirement. Investors will however need confidence that the contractual payments will be received from the transmission line users, which are likely to be national utilities. The general poor financial health of the national utilities in the region is likely to be a concern in this regard. It is instructive in this context to note that many countries in the region have experience in addressing this same issue in independent power projects (IPP) which may provide valuable lessons for developing IPT projects.

For example, possible credit support may be provided through the use of escrow accounts to prioritize payments to private sector market participants. Where this is insufficient, governments may provide sovereign guarantees

(or other government support) for payment obligations to IPTs. Additional security may also be provided by development finance institutions (DFIs). Last but not least – political commitment On a more general note, getting

any large-scale infrastructure project off the ground will require political support, government commitment and strong public governance.

For transmission projects, these factors are key in enabling inter-country negotiations, prioritization of regional projects, effective deployment of state resources and coordination of stakeholders such as regulators and utilities. This will require national governments to take a long-term view on the benefit that these projects will bring through regional energy trade, in terms of energy security, economic efficiency and ultimately the welfare and quality of life of their electorates.

Source: DLA Piper Africa Connected Issue 3: Energy in Africa – Innovation, Investment and Risk

By Simon Collier, DLA Piper, Senior Associate

It is well-known that Sub-Saharan Africa suffers from a lack of access to electricity. At the same time,

there are 22 African countries with proven gas reserves. This suggests that gas should play an increasing

role in meeting Sub-Saharan Africa’s demand for power: but is it that straightforward? Sub-Saharan Africa is, of course, a very large and diverse region made up of countries that have different natural resources, policies and challenges.

There are 13 countries in Sub-Saharan Africa currently consuming gas for power generation. Ten of those countries generate power from their own domestic gas production, two rely on pipeline imports (Togo and Benin) and one uses a combination of domestic supply and pipeline imports (Ghana). At the moment there are no LNG imports in the region, but that could soon change.

Prospects for gas-fired power generation in countries with domestic gas reserves

 There is an opportunity to expand gas-fired power generation from domestic gas production in Sub-Saharan Africa. The demand will arise not only from the need for more power in Sub-Saharan Africa, but also from the opportunity to displace oil-fired power generation with cheaper and cleaner gas. Angola, Ghana, Cameroon, Senegal and Tanzania are all examples of countries with significant gas reserves currently using oil to generate power.

Until recently, Angola was an outlier among gas producing states in Sub-Saharan Africa as it had no gas-fired power generation. In 2017 the Soyo combined–cycle natural gas turbine plant introduced 750 MW of newly installed capacity (using a connecting pipeline from Angola LNG to the power plant). In the short to medium term that project will consume a large part of currently available domestic gas resources. Further expansion in gas-fired power generation in Angola is likely to require the development of additional domestic gas resources or LNG imports.

In Ghana, gas is already a central part of the power generation mix (accounting for nearly 40% of power generation) and its role is likely to increase as oil is displaced. Anticipated demand for gas-fired power generation is such that increasing domestic gas production, pipeline imports and LNG imports may all be required. In Cameroon, Victoria Oil & Gas PLC, through its subsidiary Gaz du Cameroun (GDC), is the sole supplier of domestic gas for power generation. The government has said it requires additional grid power to meet growing demand.

In July 2019, GDC agreed commercial terms to supply gas to a proposed new 150 MW gas-fired power station, a project we are advising on, and there is likely to be scope for further growth in the country. In Tanzania, material expansion of gas-fired power generation capacity is likely to be contingent on a positive final investment decision or its proposed LNG export plant, which seems some way off. Equinor has disclosed that its production sharing agreement would allow for 10% of gas to go to the domestic market.

In Senegal, BP took a positive final investment decision on the Tortue-Ahmeyim gas development project in December 2018. A construction contract has been awarded for a floating production storage and offloading (FPSO) unit to be used alongside a floating LNG facility (a converted LNG carrier) being provided by Golar LNG. As part of that development, a pipeline to supply natural gas to both Senegal and Mauritania is planned. There have also been recent moves to expand gas-fired power generation in Mozambique: a 400 MW gas-fired power project is being developed at Temane in Inhambane province.

The plant will use gas supplied from the Pande-Temane fields. Given the recent positive final investment decision on the Area 1 LNG project in Mozambique, and the probable final investment decision Area 4 LNG project in the coming months, there could be scope for significant further expansion of gas-to-power in the country. One of the challenges is that the planned onshore LNG facilities are 2,500 km from the country’s capital and largest city, Maputo.

In May 2018 Great Lakes Africa Energy (GLAE) announced that it had signed a memorandum of understanding with the Mozambique government to build and operate a 250 MW gas-powered plant at Nacala District in the north of the country using gas from the Rovuma basin, but even that project will require gas to be transported approximately 600 km. GLAE has said it believes that mini-LNG might offer a solution.

Nigeria does not use oil for power generation. There is, however, enormous unfulfilled demand for power domestically and gas is central to plans for expansion of the country’s power sector. That  expansion has been constrained by structural problems and a chain of debt (from gas sellers to power generation companies to the Nigerian Bulk Energy Trading Company to distribution companies to end customers) not helped by the manner of the privatization of the Power Holding Company of Nigeria in November 2013.

The transmission system and gas supply network infrastructure also requires significant investment and reliability of gas supply will also need to be improved to allow a major expansion in installed capacity.

Prospects for new cross-border pipelines in Sub-Saharan Africa

 The only operational cross-border gas pipelines in Sub-Saharan Africa are the 678 km West African Gas Pipeline (which takes gas from the Escravos-Lagos pipeline at the Nigeria Gas Company’s Itoki Natural Gas Export Terminal to Benin,Togo and Ghana) and the 865 km ROMPCO Mozambique to Secunda pipeline (which takes gas from the onshore Pande and Temane fields in Mozambique to Sasol’s operations in South Africa).

In 2009 Nigeria signed an intergovernmental agreement with Niger and Algeria forthe development of the 4,400 km Trans-Sahara Gas Pipeline (1,037 km in Nigeria, 853 km in Niger, 2,310 km in Algeria and 220 km connecting Algeria to Spain). The Nigerian National Petroleum Corporation (NNPC) currently describes that project as “under consideration”.

The Nigeria Gas Company, an NNPC subsidiary, is proceeding with the project to develop the 614 km Ajaokuta-Kaduna-Kano (AKK) pipeline, the first stage of the Trans-Nigeria Gas Pipeline project which is intended to form part of the Trans-Sahara Gas Pipeline system if it proceeds. We are currently advising on the AKK project. The ROMPCO pipeline primarily supplies the PetroSA gas-to-liquids (GTL) refinery at Mossel Bay on South Africa’s southern coast (which was commissioned in 1992 as the world’s first GTL refinery).

Currently there is no gas-fired power generation in South Africa and, if that is to change, it appears more likely that gas-fired power plants would be supplied by imported LNG (import terminals have been proposed at Richards Bay and Port Coega). It is possible that pipeline exports from Mozambique to South Africa could eventually increase with the development of the Rovuma basin reserves, but this is not currently part of the development plan for either the Area 1 or Area 4 project.

The Tanzania Petroleum Development Corporation has mooted supplying natural gas to Uganda and Kenya from the Tanzanian Rovuma basin reserves. As with the expansion of gas-fired power generation in Tanzania, the development of that project will require the LNG export project to proceed, and even then the commercial viability of a gas pipeline project from southern Tanzania is uncertain.

Even where there is the political will, new cross-border pipeline projects are only likely to be developed if they can be commercially justified as a way to monetize gas reserves. In the absence of equity participation from stakeholders in upstream gas projects, governments will face an uphill battle to fund the necessary equity contribution for a new pipeline project.

Could power generated from gas be exported to regional markets?

 There are four existing power pools in Sub-Saharan Africa, within which countries have interconnected power systems: the Southern African Power Pool (SAPP), the East African Power Pool (EAPP), the West African Power Pool (WAPP) and the Central African Power Pool (CAPP). In order to expand gas-by-wire imports, transmission and distribution infrastructure will require significant development to improve capacity and efficiency.

In the medium-term, expansion of gas-by-wire seems most likely in West Africa, where land-locked countries or coastal countries with relatively small markets could take advantage of upstream gas projects (or even LNG import projects) in neighboring countries.

Prospects for LNG import projects in Sub-Saharan Africa

 A number of members of the WAPP have proposed LNG import projects, perhaps reasoning that any shortfall in domestic demand for power generated from gas could be exported around the power pool. Ghana seems closest to realizing this goal, having granted a concession to Tema LNG Terminal Company Limited (Tema LNG), a joint venture between Helios Investment Partners and the Ghana National Petroleum Company (GNPC), to construct an LNG import terminal. Tema LNG has entered into a construction contract with China Harbour Engineering Company to build onshore facilities and Jiangnan Shipyard for floating storage and regasification unit (FSRU).

LNG is reported to be supplied by Rosneftto GNPC under a 12-year supply agreement. When the construction contracts were announced in September 2018 it was said that the FSRU will be ready in 18 months, meaning first LNG imports could come as early as March 2020. One of the challenges for LNG import projects is scale.

The Ghanaian government has said that the import terminal at Tema will supply 30% of Ghana’s power generation capacity, a very large part of the feedstock requirement for a country that has significant gas reserves of its own, with the Sankofa field now supplying gas for 1,000 MW of power generation capacity (a project we know well having advised the lenders on a USD500 million letter of credit facility made available to the Ghana National Petroleum Corporation to support its role in the development of the Sankofa field). Technological developments in small-scale LNG may, in time, reduce the minimum volume requirements and open up a wider range of markets.

In July 2019 Total announced10 an agreement to develop and operate an FSRU located offshore Benin together with a pipeline to supply existing and planned gas-fired power plants, although it remains to be seen how quickly that project will proceed. In November 2016 a consortium led by Total announced that it had been granted rights to construct an FSRU in Cote d’Ivoire11 together with a pipeline connecting the FSRU to existing and planned power plants in Abidjan but no final investment decision has yet been announced.

South Africa continues to explore options for a LNG imports12 and an LNG terminal has also been proposed at Walvis Bay in Namibia. Other LNG import projects in the region have either previously been considered and put on hold (such as in Kenya)14 or are currently under consideration (such as in Mauritius and the Seychelles). Given that a delivered gas price of around USD8/MMBtu is competitive with oil-fired power at an oil price as low as USD50/barrel;17 it is more than possible that the economics will support LNG imports to displace oil-fired power generation and to increase power generation capacity in Sub-Saharan Africa, particularly where funding can be obtained from multilateral lending agencies or development finance institutions.

Although the World Bank has announced that it will no longer finance upstream oil and gas projects (apart from in “exceptional circumstances”), it is expected to continue to finance midstream and downstream natural gas projects.

There are challenges to gas-to-power projects in Sub-Saharan Africa, such as the poor records on collection of power sector revenues in many countries, related problems of creditworthiness of the state utilities who are the natural customers for gas-to-power projects and underinvestment in electricity distribution infrastructure, but those challenges can be overcome and are present whatever the means of generating electricity.

In countries with domestic reserves, gas can undoubtedly play a major role in the development of power generation capacity. LNG import projects are also foreseeable as countries seek to move away from oil as a power generation fuel. New cross-border gas pipelines may be less likely, but LNG imports or increases in domestic production could well result in an increase in gas-by-wire exports, particularly to land-locked countries in the WAPP.

Source: DLA Piper Africa Connected Issue 3: Energy in Africa – Innovation, Investment and Risk