Market Design for Multilateral Trade of Electricity in ASEAN: A Survey of  the Key Components and Feasibility^*

The economics, financial feasibility, prioritization of power grid interconnection projects, and basic technical and physical harmonization of power grid operation and regulation required have been studied by academia as well as international organizations. Table 1 summarizes the important findings from the past studies on the APG.

The trading of electricity in ASEAN is currently limited to the bilateral mode, however. To develop the APG and achieve its full potential for economic and social benefits, multilateral trading of electricity is needed. The recent Lao PDR–Thailand–Malaysia energy integration initiative by these countries, demonstrating the cross-border trading of electricity among them through negotiated terms and agreements, clearly indicates the strong willingness of the ASEAN countries to develop multilateral trading of electricity.

Therefore, at this junction, the key issues to be discussed include the liberalization of national electricity markets, the harmonization of the operation, and the regulation of the transmission system, especially the cross-border power grid interconnection, the electricity market framework/model for the region, coordination in network planning and capacity development, the development of common algorithms for capacity allocation, and the sharing of infrastructure on the basis of fair compensation (Rakhmah and Li 2016; IEA 2019).

This paper thus aims to review comprehensively the key components and feasibility of establishing an interconnected and competitive multilateral electricity market within ASEAN countries. A survey method is adopted to collect opinions from utility experts as well as energy policymakers from the ASEAN member states regarding the acceptability and feasibility of an ASEAN electricity market framework/design. Section 2 provides a literature review on the issue, especially referring to existing market models from other parts of the world, such as the European Union regional electricity market. Section 3 presents the methodology of the survey on the opinions of power sector experts in the ASEAN. Section 4 discusses the results and key findings of the survey. Section 5 concludes and draws policy implications.

The EU represents one of the most advanced regions in interconnection in terms of the electricity markets’ integration across borders. Section 2.1 summarizes the lessons on the overall market design. Section 2.2 highlights the key components of such a market design as functioning integration of the electricity markets in ASEAN.

The increasing concern for energy supply security has pushed the EU member states to formulate a common energy policy that allows energy to flow freely across borders. The Lisbon Treaty and the adoption of the Third Energy Package made a clear commitment to the completion of the Internal Energy Market by 2014, allowing free flow of gas and electricity across borders. In 2006, the EU created seven regional electricity markets, marking an interim step toward the target of a single European electricity market in which energy would be traded freely across borders. The seven regional markets are the France–UK–Ireland, Central-East, Central-West, Central-South, South West, Baltic, and Northern markets (IIEA 2014).

Electricity in the organized spot market is mainly traded in an intraday market and single day-ahead market through implicit auctions. The transmission capacity and electricity are traded together in the implicit auction, which is also known as market coupling. In the intraday market, participants trade closer to real time and trading mostly takes place during the operation day.

Such trading requires the calculation of the available cross-border capacity in a coordinated manner at the regional level to ensure reliable capacity calculation and the availability of the optimal capacity to the market. Transmission System Operators (TSOs) establish a common grid model that covers the estimation of electricity generation per hour, load, and network status to achieve this integrated calculation. This mechanism allows power to flow from low-price to high-price areas. The market coupling operator uses a common algorithm, the so-called European Hybrid Electricity Market Algorithm (EUPHEMIA), to match bids and offers optimally. The results from this calculation are made open to all the power exchanges in a non-discriminatory manner.

At the same time, electricity can be traded in derivative markets (forward markets), in which suppliers can buy and use long-term and forward contracts in advance to cover their consumption portfolio. The derivative markets could also include explicit auctioning to allocate long-term transmission rights to market participants as financial transmission rights (FTRs) and physical transmission rights (PTRs). These derivative markets aim to reduce the risk associated with an electricity price hike and to secure the electricity supply (ENTSO-E 2013).

The integration of the European electricity markets started with a top–down process of liberalization and coordination. The European Commission adopted a set of directives and regulations known as the Third Energy Package on 3 March 2011. The package targeted reform in five main areas: (1) ownership unbundling, which stipulates the separation of energy suppliers from network operators; (2) strengthening the independence of regulators to generate a competitive internal energy market and to ensure that regulations are fairly implemented and enforced; (3) the establishment of the Agency for the Cooperation of Energy Regulators (ACER), which plays a central role in encouraging electricity market integration and enhancing competition through the development of the EU-wide network and market rules; (4) the cross-border cooperation between the TSO and the creation of the European Network of Transmission System Operators for Electricity (ENTSO-E); and (5) increased transparency in retail markets to benefit consumers (European Commission 2016).

Looking at the situation of liberalization and deregulation of electricity markets across ASEAN, Singapore was the first country to launch a competitive, liberalized, and deregulated electricity market. The Philippines and Vietnam followed the trend by establishing a competitive wholesale electricity market. Indonesia, Malaysia, and Thailand have achieved partial liberalization, specifically including the unbundling of transmission and generation, corporatization of utilities, independent power producers, an independent regulator, and third-party access, but have yet to introduce wholesale competition into their electricity market (Sen et al. 2017).

ASEAN has established the Heads of ASEAN Power Utilities/Authorities to coordinate the utility companies in the ASEAN as well as the ASEAN Power Grid Consultative Committee to coordinate the electricity market regulators and policymakers in the ASEAN. These bodies function more as a secretariat, however, than as formal institutes to carry out regular coordination activities such as harmonization, infrastructure planning, monitoring and exchange of operation information, and so on. The region thus has yet to establish formal institutions, like ACER and ENTSO-E in Europe.

The multilateral trade of electricity in the ASEAN will most likely be developed as a loose over-the-counter market first. Eventually, however, it will have to evolve into organized markets to cater to the needs of active regular trading of various products and services, as described in the next two subsections.

To establish a multilateral electricity trading framework in the ASEAN with the basic functions, we identified the following basic building blocks to be developed.

Open access to transmission and distribution grids by market participants from all member states is a fundamental step toward the integration of electricity markets. Opening access to the grid is a long-term process rather than a discrete event. The initial step toward open access is to enforce legal rights for suppliers to access the grid and to sell their electricity and capacity and for buyers to have an agreement with suppliers, whether it is a direct agreement or one reached through an authorized market operator. The institutional requirement at minimum includes transparency in regulations and procedures on market and grid operations, unbiased TSOs, and financial objectives (World Bank 2013).

In a liberalized electricity market, the available cross-border capacity should be calculated in a coordinated manner; in the European electricity market, the calculation is conducted by TSOs. The network code on capacity allocation and congestion management regulates the available capacity trade. The forward capacity allocation network code, on the other hand, regulates long-term capacity trade, whereby TSOs establish a common grid model according to the individual grid model from each TSO. This model incorporates the generation estimates, hourly load, and network status.

Electricity trade also involves cross-border electricity flows and normally leads to electricity losses. Therefore, compensation is necessary for the infrastructure costs for hosting cross-border electricity flows and the costs for electricity losses incurred by particular transmission systems that host cross-border flows. The European electricity market has established the Inter-TSO Compensation mechanism to compensate for electricity losses and grid congestion (EC 2010).

There are two components to the calculation of compensation. The first component is the transmission losses based on a with-and-without-transit model. Losses are calculated for each TSO's transmission grid in a load flow situation with and without transits. TSOs are compensated for the costs incurred as a result of hosting cross-border electricity flows on their networks. In addition to this, the national transmission system operator from which cross-border flows originate and the systems where those flows end provide the compensation. Compensation is made on a regular basis with regard to a given time period in the past (EC 2010).

The second component is an infrastructure cost to compensate for hosting cross-border flows. The level of payment for this infrastructure is based on the infrastructure cost asset value used to host cross-border flows and the amount of cross-border flows between participating TSOs. The cost calculation for hosting cross-border flows is established on the basis of forward-looking long-run average incremental costs that also incorporate investment in new infrastructure, account losses, and an appropriate proportion of the existing infrastructure cost (Androcec et al. 2011). The benefits incurred as a result of hosting cross-border flows are also taken into consideration to reduce the compensation payment.

Market coupling is one way to achieve market integration. It takes place in a network that consists of several areas or countries, among which market transactions will be settled through a common algorithm that takes grid constraints into account. If there are differences in the market area prices, then the operators will calculate the tradable transmission capacity in their market areas to even up the price in the coupled markets. A system price is thus created through this mechanism (Toljan et al. 2011).

However, in circumstances in which the necessary trading capacity exceeds the interconnector capacity, bottlenecks occur and the market is necessarily decoupled. Subsequently, the prices between previously coupled areas will differ and these areas will no longer use the system price. It implies that, without sufficient interconnection between different markets, a single price system cannot operate. Thus, bottlenecks will create different prices in each of the bidding areas even if they are in the decoupled market. This is known as the market splitting procedure (Van den Bergh et al. 2016).

Nodal pricing is a method to determine market clearing prices, which are calculated in a number of locations on the transmission grid, known as nodes. Nodes refer to each point on the transmission system at which generators inject energy or loads withdraw energy. Because nodal prices reflect the marginal costs of electricity provision at different locations, these prices give incentives for the trading of electricity (Oren et al. 1995).

Nodal prices may be different at the individual node in the network where a single transmission line is contested (Stoft 1997; Hogan 1998). Hence, network nodes are segregated into price zones that share similar prices. This approach is known as zonal pricing, which is also called market splitting (De Vries and Hakvoort 2002).

Based on the literature review, we summarize the guiding principles of the market design for multilateral trading of electricity in the ASEAN as follows:

1. Maximize the economic potential of the APG;

2. Ensure the safety and reliability of the ASEAN member states’ power grid;

3. Incentivize transmission infrastructure investment; and

4. Enable open access and a common transmission capacity mechanism.

However, we fully understand that the feasibility of such an ideal market model is subject to the reality of ASEAN member states, especially concerning their own electricity market structure, legislation, regulations, standards, and even politics. Therefore, we conducted the first round of the survey on the following five blocks of issues:

1. Part I: General opinions on multilateral electricity trade;

2. Part II: The feasibility of establishing ASEAN multilateral electricity trade based on the APG;

3. Part III: Institutions for third-party use of transmission capacity in ASEAN multilateral electricity trade (estimation, allocation, and compensation);

4. Part IV: Market design for multilateral electricity trade in the ASEAN; and

5. Part V: Setting up institutions for coordination and cooperation in multilateral electricity trade.

The first round of the survey produced indicative results of the components and the kind of overall institutional framework that are preferred. However, a common market model derived from such preferences and thus customized for the ASEAN is still to be recognized as acceptable to most member states. Therefore, a second round of the survey was conducted to assess the acceptance of a two-stage market development model for ASEAN.

The questionnaire for the first-round survey as well as the second-round survey contains questions that scale the responses to five levels, from very negative, negative, and neutral to positive and very positive.

The first-round survey received a total of seventeen responses from experts from nine ASEAN countries. The opinions collected from the survey can be summarized in three categories:

First, issues that have been confirmed or agreed by most experts, which include the following:

• The majority of respondents lack knowledge about competitive multilateral electricity trade in an integrated market, such as the EU and U.S. regional markets;

• ASEAN cannot follow any existing market models and needs its own market design due to its own characteristics;

• ASEAN needs common guidelines for the technical and physical interconnection of power grids;

• ASEAN countries can share data about cross-border transmission capacities;

• The net transfer capacity should be used in estimating the available cross-border transmission capacity;

• ASEAN needs a common model to estimate the loop flow in the cross-border interconnections and compensate for it accordingly;

• Any of the methods, namely, market splitting, market coupling, and nodal pricing, could be used to manage congestion in cross-border transmission interconnectors;

• ASEAN countries agree to set up several institutions to support and coordinate issues related to an ASEAN common electricity market, including a planner group, regulator group, and TSO group, as well as an ASEAN-wide infrastructure development plan; and

• ASEAN countries agree to establish a special financing fund for an ASEAN common electricity market.

Second, there is a weak preference for or motivation to develop the following issues in the ASEAN electricity market:

• A common market model for electricity pricing;

• A common guideline/coordinated method for the allocation of cross-border transmission capacity and compensation for open access;

• A common methodology for the configuration of trading/bidding areas/nodes;

• ASEAN countries can share data about domestic electricity generation, transmission, distribution, and load;

• Implicit auctioning of cross-border transmission capacity for the trading of electricity in the ASEAN context;

• PTR and FTR can be useful for market participants to manage better the risks related to transmission; and

• An ancillary services market is necessary as an integral part of the future ASEAN integrated electricity market.

Third, there are several issues that the majority of experts perceived to be less important and infeasible in ASEAN:

• An explicit auction of available cross-border transmission capacity;

• The development of PTR or FTR to incentivize investment in the cross-border transmission infrastructure;

• A common guideline for the grid operation procedure, performance standards, and grid codes; and

• Liberalization or unbundling in the domestic market of the ASEAN member countries.

Based on the information collected and comprehended during the first round of the survey, we can identify components that are commonly agreed to be the building blocks for the beginning stage of market development in the ASEAN. Less-preferred components serve as the building blocks for an advanced stage of market development in the ASEAN. The second-round survey on the feasibility of an electricity market grand design generated eleven responses from eight ASEAN countries. To avoid overweighting the opinion of a country with more responses than others, we take the average of the responses from the same country. Therefore, in the following Table 2, the outcome of the survey is presented as the scoring of the opinions of eight countries.

The results of the second round of the survey reaffirmed the previous finding that certain components are readily acceptable among most ASEAN countries and are in principle sufficient to support a regional electricity market for multilateral trading. Nevertheless, moving toward a more organized and competitive market in the region (i.e., components 7–10 in Table 2) requires deeper structural reforms of the domestic electricity markets, legislation, and regulations—for which the preferences of most ASEAN countries become neutral.

First, the policymaker group aims to achieve consensus and agreements at the policymaker level to foster more harmonized multilateral electricity trade. This group especially targets the improvement of the way in which the internal electricity market functions as well as addressing structural issues.

Second, the regulator group is responsible for monitoring the functioning of the cross-border electricity market. It will need to provide a framework for market integration, which will serve as a base for formulating a set of common guidelines that govern both the power systems and the power markets.

Third, the TSO group is responsible for coordinating and maintaining effective and transparent access to the transmission networks across participating countries. It also provides a common platform that governs the way in which electricity is produced, traded, transmitted, and distributed.

Finally, the ASEAN-wide planning⁶⁷ group develops a coordinated approach to region-wide infrastructure planning and aims to develop and promote a financing mechanism for the APG.

We hope that this illustration clearly explains how a regionally integrated electricity market works and what the necessary building blocks are. The ideal market model will depend on the preferences of the ASEAN member countries, however—particularly taking into consideration the existing legislation, regulation, and market structure in each member state.

In conclusion, a two-phase market development strategy is recommended for ASEAN to move forward into an integrated electricity market. Such a strategy would be based first on the experiences and lessons learned from the EU integrated electricity market. The proposed framework/model is subsequently tested through a structured survey on the feasibility as well as the priority sequence of developing the necessary building blocks.

In phase 1, to facilitate sporadic multilateral trade of electricity, the following are considered as the necessary building blocks:

• Enabling open access;

• Sharing data and information for coordinated planning and development of the power infrastructure;

• Coordination for the allocation of available cross-border transmission capacity; and

• A compensation mechanism for open access to the grid.

Then, for phase 2, the following should be developed to establish a fully integrated regional electricity market:

• Harmonization of technicalities, standards, and principles;

• Mandate a minimum interconnection level;

• A gradual shift to nodal/zonal pricing;

• Organized day-ahead and intraday markets; and

• Develop balancing service and financial (futures) markets.

Our findings coincide with and reaffirm the main policy advice given by the study on the feasibility of multilateral power trade conducted by the International Energy Agency for ASEAN (IEA 2019), which offered ASEAN the options of developing a “secondary” market model first before moving to a “primary” market model. Our study also further explored the feasibility of the building blocks in each phase of market development. The survey showed a certain extent of consensus among ASEAN countries on these issues and thus the validity of the proposed two-phase framework/model.