HomeIndustry SectorsFinance and PolicyHow to capture the value of transmission projects

How to capture the value of transmission projects

By Elsie Mbugua, director at Leadwood Energy in Kenya and Mark Hughes, a partner with 3 M Energy Advisors in UK

Transmission project development is seen by many as the next nut to crack in improving security and quality of supply to consumers.

However, analysis shows that transmission continues to be the weakest link. Let’s examine global transmission business models to highlight potential solutions.

This article first appeared in ESI-Africa Edition 1, 2019. You can read the magazine’s articles here or subscribe here to receive a print copy.

With several projects cited in East and West Africa it is evident that steps are being taken to promote transmission projects as noted in the World Bank and Power Africa transmission road maps. However, transmission remains a neglected part of the power sector value chain across Africa. According to the World Bank, of 38 countries on the continent, their combined length of transmission infrastructure is 112,196 kilometres (km). Notably, the length of transmission lines in Africa is 247km per million people compared with 339km in Peru, 694km in Chile and 807km in the US (World Bank, Linking up Public-Private Partnerships in Power Transmission in Africa).

Going forward, transmission projects will need to move in tandem with additions to generation capacity by designing alternate financing that relieves the financial burden from governments while also focusing on the delivery of value addition projects. It will be essential in the delivery of transmission projects that the expected value of the benefits obtained exceed the costs of installation and operation. White elephants need to be avoided. Positive cost benefit analyses will be a necessary precursor to transmission and interconnection projects before they can be supported by the European Union as a “Project of Common Interest”.

Thoughtful policy and execution will be fundamentally important as an underpinning to long term viability. But, positive cost-benefit analyses will not be a sufficient condition to making projects happen. For this to transpire, there needs to be clear, legal governance and regulation treatment of the assets/ businesses being established; and transparent and reasonable incentive arrangements in delivery and operation, which will help assure that the forecast benefits are actually achieved. These core components will be essential for attracting private sector participation and financing.

Global case studies supporting return on investment strategies

Transmission tends to be defined as high voltage (HV) from 120kV up to 400kV and more. It differs from distribution in its primary purposes being typically installed to connect generation and distribution networks, facilitate merit order dispatch and operate in AC mode – transferring power from generators connected to the HV transmission grid to bulk supply points (BSPs) – from which distribution networks allow power flows to retail customers.

Beyond this simple definition, transmission projects create access to cost efficient generation, enable the integration of intermittent renewables (such as wind and solar), ensure that the power system remains in balance and reduce reserves that may be needed to ensure security of supply.

In Thailand, when EGAT (the Electricity Generation and Transmission Authority of Thailand) plans the development of its National Grid System it justifies transmission project development on the basis of the expected development of load around the country and from imports (eg from Laos). The Authority also focuses on the most efficient way to develop the overall network and the expected/forecast load flows with minimum losses, while meeting network security standards. Approved projects get admitted into the Regulated Asset Base (RAB) to earn a reasonable return as approved by the Energy Regulatory Commission (ERC). This approved RAB plus relevant reasonable operating costs feature in the subsequent tariff calculations to give comfort to EGAT shareholders and financiers and enable EGAT to arrange such financing from the market at reasonable margins.

Transmission can be operated in DC mode and, in particular, when operated as a means of transferring power over long distances and connecting sources of generation to load centres. Engineers generally use a rule of thumb about whether AC or DC lines are best constructed considering the scale of the power transfer and the distance (eg above or below 250kms).

Brazil benchmark

Brazil organised 38 tenders of multiple lots from 1999 to 2015. These resulted in the award of 211 concessions and 69,811km of transmission lines designed, built and operated under BOOT contracts. Almost 70% of investments in transmission between 2000 and 2010 came from the private sector. Brazil uses a revenue cap scheme to regulate transmission, which is set by the outcome of the tenders. Furthermore, the competitive tendering resulted in reduced costs in transmission lines.

Peru benchmark

Peru organised 18 transmission tenders from 1998 to 2015. These tenders resulted in $1.8 billion of investment and more than 6,000km of transmission lines (and associated substations), designed, built, and operated by the private sector under BOOT contracts. Today, the transmission sector is entirely private (completed through a gradual process) and is operated by 13 companies with the exception of a few transmission lines in isolated areas of the country.

Chile benchmark

Chile organised seven tenders from 2007 to 2015. Ten projects were awarded for a total of 1,200km under build, own and operate (BOO) contracts. When the government awards the tender to a transmission company, the company obtains the rights to build and operate the transmission line by a ministerial decree. The decree also gives the company rights to transmission revenues. Transmission companies do not sign a concession contract with any counterparty. Transmission companies are paid against timely commissioning and availability of the line and do not incur demand or other risks related to the operation of the whole grid. Until 2016, generation companies paid transmission tolls in proportion to their use of the transmission lines. However, since 2017 the transmission charge has been paid directly by end users twice a year. The government does not own power sector assets and transmission companies never transfer the assets to the government.

India benchmark

India’s private sector developed over 21,000 circuit km of lines between 2006 and 2016 (equivalent to 6.1% of the total network) and invested a total of 5.5 billion from 2006 to 2015. There is also a projected pipeline of $5 billion worth of projects. Transmission is mainly owned by government owned companies and since 2006 interstate transmission has mainly been tendered, although exceptions remain for projects of ‘strategic importance’ or time bound delivery. The private sector can only participate in transmission through competitive bidding. Private bidders can form JVs with PGCIL (India’s central transmission utility) for tendered projects. About ten private companies are involved in private provision of transmission in India. They include transmission specialists, integrated power companies or broader Industrial conglomerates. The Indian government is also considering relaxing rules to allow investment funds to participate directly in transmission projects. Lines are built on a build, own, operate and maintain (BOOM) basis for a 35-year period.

In Canada, NALCOR (Newfoundland and Labrador Energy Corporation) decided to develop its Muskrat Falls resource, a 600MW hydro facility on the Churchill River. It planned and funded both the generation and the transmission assets (over thousands of kms) to connect the hydro generation in Labrador to the load centre in Newfoundland. This took account of the consequent capability to shut down older, inefficient fossil-fuelled plants and export the new power to other energy consumers down the Maritime Coast.

The finance raised to fund the two developments was structured in two tranches; one for the generation component and one for the transmission component, which included a sub-sea stretch of line positioned on the sea bed.

The regulatory framework determining allowable revenues for each component was different. The transmission component or the assets were entered into the Regulated Asset Base of the utility, which allowed a defined stream of revenues to enter into network charges with customers over the life of the assets and with a given depreciation rate reached for an agreed return on capital.

Transmission can allow switching of the direction of power flows and in addition, provide inter-connected components of connected systems additional security of supply both in long-term generation and short-term operation. Whilst transmission project development tends to seek secure returns over a transparent and pre-agreed timeframe, there are many variations on this, adapted to meet specific circumstances.

In the latest BritNed interconnector (England to the Netherlands), which comprises a 400kV line and 1,000MW plant, the TSOs (Transmission System Operators) are the investors, namely National Grid and Tennet. These TSOs are required to offer open access to the interconnector and rely primarily on income they can achieve from charges made through auctions for access.

However, the structure allows for a fall back to protect income to service asset capex and operation costs if insufficient funds are delivered by the auctions. This deficit is charged directly to the customers.

One of the more intriguing components of the development of transmission projects is the diversity of the rationales for such developments and, more recently, the alternative sources of private sector financing in other parts of the world. African governments continue to be constrained by fiscal limitations and have no experience with privately financed transmission lines. By drawing from private sector participation in other low income countries, these solutions should help unleash the financing constraints and overcome the transmission deficit.

Through policy reforms in the 1990s Brazil, Peru, Chile and India succeeded in mobilising over $24.5 billion from the private sector between 1998 and 2015, which enabled close to 100,000km of transmission lines (World Bank, Linking up Public-Private Partnerships in Power Transmission in Africa). These countries were all low income at the time of policy reforms and had vertically integrated systems like most African countries. Their solutions offer an ideal opportunity to draw from best practices and lessons.

Other specific examples of business models in more developed countries that provide lessons to be learned

Project 1: Moyle Interconnector a 250kV 500MW transmission between N. Ireland and Scotland

Project structure: Final Commercial Operation in 2002. Initially rationalised on the basis of a 100% power transfer from Scotland to N. Ireland with a backing Power Purchase Arrangement (PPA) from a Scottish utility to Northern Ireland Electricity (NIE). Initial sources of value were;

a) Lower power purchase costs for the NIE consumer underpinned by firm (index-linked) price PPA,

b) Shut down of inefficient fossil fuelled power stations in N. Ireland, c) Enhanced security of supply for N. Ireland, and

d) Higher load power plant load factors on the Scottish PPA counterparty.

Moyle was subsequently put at arm’s length to NIE and now operates in a separately owned and controlled mutual business.

The structure operates on a trading basis between N. Ireland and Great Britain by selling space on the interconnector in regular auctions.

The regulatory and commercial basis and ownership arrangements evolved in step with the evolution of market trading arrangements from a starting Single Buyer model to the current competitive trading market models.

Significance: The project was originally funded on the Balance Sheet of Northern Ireland Electricity. Once operational it was transferred to an Independent Power Transmission project, which now earns its money on a merchant basis and operates as a mutual.

Project 2: AESO Fort McMurray West 500kV Project

Project structure: The Alberta Electricity System Operator (AESO) is the not-for-profit independent entity responsible for the safe, reliable and economic planning management and operation of the Alberta Electric System in Canada. In 2010, it decided to design the tender for electricity transmission projects by independent transmission operators (ITOs).

It looked at risk transfer, availability, and reliability incentive arrangements and a procurement process to deliver best value. This led to the Fort McMurray 500kV project and the process to choose an ITO. The sources of value it wished to deliver and secure were:

a) The increase in additional transmission capacity to meet expected new power demand in the North West of the Province (when most existing generation was in the South);

b) A competitive procurement process to get the best long term, all-life value proposition for the delivery of the new transmission lines (not just from incumbent transmission operators); and

c) Establishing new benchmarks in transmission project implementation and performance to enable a broader development of its own incentive-based regulation to transmission in Alberta.

Significance: The project provides an example of an unbundled structure, which sufficiently and adequately ensures the effective separation of transmission networks from generation and supply interests.

Project 3: Oman TransmissionPrivatisation (transaction on-going)

Project structure: The Oman government is currently engaged in selling a 49% stake in OETC, the country’s electric transmission business. The rationale for the sale has several components including;

a) The recognition of the significant new-build transmission projects estimated at some $1 billion in the next five years; b) The perception that the costs for this new build could be reduced by partnering up with an experienced third party as an equity participant; and

c) Removing requirements on the Government Exchequer to provide funds for such investments.

Significance: This structure is a partial privatisation of the transmission business to raise adequate capital for new projects while also benefitting from third party expertise in constructing new transmission lines.

Four primary concluding remarks

The sources of value from transmission projects and methods of attracting alternative financing can differ substantially and therefore capturing these sources of value in contractual and regulatory arrangements to facilitate their delivery will also have diverse solutions. Governments should draw on the substantial body of international experience to identify lessons learned elsewhere.

1. It is important to be really clear on the primary cost-benefit rationale and who the beneficiaries are, and by how much they are likely to benefit. This will help locate the value sharing agreements (eg in the form of long-term PPAs and potential access and trading arrangements) and subsequently the way the transmission project may be able to attract finance.

2. In evolving growth markets, it is important to leave options for the transfer of transmission assets to alternative ownership arrangements.

For example, if there is a foreseeable transfer of Special Purpose Vehicle assets to a national transmission utility then ensure the transfer price is reasonable.

3. Adopt forward looking perspectives of how the cost-benefit analysis and markets might evolve from a financeraising perspective and therefore pave this future perspective and development opportunities with a security package, which recognises their legitimate concern to achieve security around reasonable returns. If this path is not clear investors will not show up.

4. Pilot projects are a good idea. They will test and allow evolution. It will be important to get the best projects tested first to create a track record for investors to look back to.

Introducing a new business model has risk so a pilot allows for better understanding of the implementation challenges, and revised regulations and policies as necessary to improve efficiency.

About the authors

Elsie Mbugua is an energy thought leader focused on finding solutions for Africa’s complex energy issues through the Leadwood Energy and LCo. platforms. She is an entrepreneur and energy trader advising governments and multinationals on energy related issues in Africa. Previously she worked as a physical energy trader for some of the world’s largest trading houses – JP Morgan and Goldman Sachs – in crude and products, coal, emissions, power, natural gas, and liquefied natural gas. This includes a focus on the logistics of the physical markets and the financial products for each of the commodities.

Mark Hughes provides economic and advisory services to the global energy and utility (E+U) sector as a Partner in 3 M Energy Advisors and for 21 years previously as Partner at PwC. He advises businesses facing changes in their policy and regulatory environment, including privatisations and introduction of new markets and competition. This includes the overseeing of the analyses of the financial impacts of such changes and consideration of the best way to preserve value, avoid adverse impacts or take advantage of new opportunities.

This article first appeared in ESI-Africa Edition 1, 2019. You can read the magazine’s articles here or subscribe here to receive a print copy.

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