A variety of market designs for electricity across the globe
This is the second installment of the Topic of the Month: Thirty years of electricity markets
Thirty years of electricity markets
Many countries and jurisdictions worldwide have introduced open markets in their electricity industries over the past 30 years. Different approaches have been implemented and tested. Even in the same country or jurisdiction, reforms and adjustments have frequently followed the initial restructuring to incorporate the lessons learnt and react to changing conditions in technology, commodity prices and policy.
In this second episode of the Topic of the Month, we will highlight the main insights from the chapters of the Handbook on Electricity Markets, devoted to the discussion of the details of electricity market designs in specific countries or sub-regions of countries, their strengths and weaknesses, and their evolution in response to those weaknesses and changes in public policy.
Electricity market designs across the globe
A prime example of the constant evolution of electricity markets over time is provided by Great Britain, which restructured and partially privatised its electricity industry in 1989-90. A power pool was introduced first, but it soon proved unsatisfactory, given the presence of a de facto duopoly. The New Electricity Trading Arrangements (NETA) replaced the Pool in 2001 and improved the competitiveness of the British wholesale market; however, NETA failed to spur adequate investments in new generation capacity, both conventional and renewable-based. Given the ageing of the British generation fleet and the political goal of decarbonising electricity, an Electricity Market Reform was adopted in 2011-13, introducing a capacity remuneration mechanism and contracts for difference to underpin the deployment of low-carbon generation assets. These significant changes in market design suggest how complex the delivery of successful electricity markets is and how material legacy conditions are (for more information on the strengths and weaknesses of the British market model, look at Chapter 6 by David Newbery).
Very different background conditions and market design options are observable in the case of PJM Interconnection, the biggest organised wholesale market in the US. Covering the largest part of 13 states located east of the Mississippi river, PJM is the result of a long tradition of cooperation among neighbouring electric utilities, which gradually expanded and started implementing open markets in the 1990s. Formally a regional transmission organisation, PJM is responsible for the operation of the market and the electricity system. Different from the case of Great Britain and the European Union (EU), PJM fully integrates the day-ahead and the real-time market, ensuring a co-optimisation of the supply of both electricity and ancillary services. On top of that, PJM makes use of a bid-based, security-constrained economic dispatch with locational marginal prices (LMP). After an unsatisfactory experience with a single market-clearing price for its entire footprint, PJM introduced LMPs, which have the advantage of automatically incorporating transmission constraints and network losses. Price caps to avoid the exploitation of market power, financial transmission rights and a capacity remuneration mechanism were later introduced to foster the ability of the market to provide short and long-term efficient signals (for more information on the strengths and weaknesses of the PJM market model, look at Chapter 7 by William Hogan).
A different recipe for successful electricity markets is the one implemented in ERCOT, the electricity market that covers most of Texas and that operates almost in isolation from the rest of the US power system. Subject only to the oversight of the Public Utility Commission of Texas, ERCOT has benefited from consistent policy directives from the Texas Legislature, growing electricity demand and an abundant endowment of natural gas, wind and solar energy. Free market ideology has profoundly inspired the development of ERCOT’s market design, whose main features are the use of LMPs, very high price caps at the wholesale level, an operating reserve demand curve for remunerating reserve capacity available during periods of tight supply-demand balance, and full retail competition with no default tariffs for residential customers. Of course, the prolonged blackout of February 2021 cast a shadow on the past positive performance of ERCOT and raises questions about its ability to ensure security of supply; nonetheless, ERCOT shows that in “normal” conditions markets can deliver good prices for customers and integrate efficiently a growing share of intermittent renewables (for more information on ERCOT, the success so far and the lessons learnt, look at Chapter 8 by Ross Baldick, Shmuel Oren, Eric Schubert and Kenneth Anderson).
ERCOT is not alone in relying on an energy-only market. Established at the end of the 1990s, Australia’s National Electricity Market (NEM) has no dedicated capacity remuneration mechanism either. Its core is a real-time market that provides a single price for the entire footprint, basically East and South-East Australia, every five minutes. Forward markets have emerged over time and provide market players with the possibility to hedge prices and secure the necessary long-term revenue streams that underpin investment in new generation capacity. A very high price cap ensures that capacity costs are covered during peak hours. The results of this market design have been generally positive, at least until 2016, when a blackout affected South Australia. From roughly that year, sudden changes in the national climate policy, significant turmoil in the natural gas market, an ill-managed retirement of coal power plants, and mistakes in the regulation of network charges have led to a substantial increase in wholesale and retail prices. Dissatisfaction with free markets has prompted state governments to intervene and, in some cases, re-regulate the retail segment of the industry. The penetration of intermittent renewables, both at the transmission and distribution level, has made the challenges even more pronounced (for more information on the lessons derived from Australia’s experience with open electricity markets, look at Chapter 9 by Paul Simshauser).
Energy-only markets also characterise the Nordic countries in Europe (Norway, Sweden, Finland and Denmark). In the 1990s, they pioneered not only open markets for electricity but also integration at the regional level. Via the creation of Nord Pool, the transmission system operators of the Nordics established a common day-ahead market with zonal prices, while retaining control on congestion management. Thanks to abundant hydro resources and legacy investment in nuclear, the Nordic market has recorded relatively stable and low prices for electricity. The completion of several interconnections has allowed the exploitation of complementary national generation mixes and the achievement of high levels of security of supply. Over time, public policies have supported the uptake of new renewables, mostly wind energy and biomass. However, despite these successes, some areas of uncertainty persist. The future role of nuclear power, for instance, is unclear. Unclear are also the policies that will further support the penetration of renewables and the concrete possibility of achieving the decarbonisation of the entire economy by 2050 (for more information on the strengths and weaknesses of the Nordic market model, look at Chapter 10 by Chloé Le Coq and Sebastian Schwenen).
In parallel to the integration of the Nordic electricity markets, significant efforts took place in continental Europe. A gradual harmonisation of technical rules for trading electricity and operating the power system – the so called network codes – supported the establishment of an internal market for electricity that today covers almost all EU member states (plus Norway). The starting point of this converging process has been the coupling of national day-ahead markets, followed more recently by the integration of intraday and balancing markets. However, this successful story is now at risk due to a lack of coordination of national policies. The increasing attention of European policymakers on the decarbonisation agenda and security of supply is justifying the adoption of public interventions at the national level that affect the functioning of liberalised markets and may jeopardise the common results achieved in the past two decades. In this context of differentiated, national, “hybrid” markets, a more integrated approach towards planning and the deployment of key infrastructure might be required (for more information on the strengths and weaknesses of the European market model, look at Chapter 11 by Fabien Roques).
If you want to hear more from the contributors of the handbook and their assessment of the experience with electricity markets in Europe, North America and Australia, look at the recording of the joint webinar hosted by FSR and IAEE on 11 October 2021. You may also download the presentation of the speakers here.