In August 2003, Ireland’s Commission for Energy Regulation (CER) announced new wholesale electricity trading arrangements that will come into effect in 2005. According to the Commissioner, Mr. Tom Reeves: “. . . the new market arrangements for the buying and selling of electricity represent a fundamental change in the way electricity will be traded in Ireland . . .”
The new market design selected is a mandatory energy-only centralised pool with marginal pricing calculated in each half hour of the day. Generators - subject to certain provisions - will make offers to generate quantities at particular prices. The System and Market Operator will select the preferred offers on the basis of their price and location. The offers are chosen and plant dispatched to minimise the cost of supply to the market taking account of transmission losses and constraints and ancillary services. This results in a separate marginal price at each location that reflects the marginal cost of energy at that location. The same locational marginal price is paid to all metered generation in that period at that location. Supply companies will purchase power at a single uniform customer price that is the load-weighted average of the locational prices.
Ireland undertook extensive consultation with market participants and other stakeholders in the market review, including a number of industry tutorials aimed at explaining market concepts to participants and other interested parties. The International Energy Agency (IEA) in its Energy Policies of IEA Countries, Ireland 2003 Review, said of the review: “…This review [of electricity trading arrangements undertaken by the CER] is both comprehensive and admirably consultative so that it is highly probable that the new market rules will be much better designed to accommodate successful competition in the sector.”
In the review, Ireland defined the objectives for the new market, defined several internally consistent market approaches, and then evaluated these approaches. Throughout this process, the actual experience in markets that were similar to Ireland were examined to find features tested and proven to provide comfort that a market design could, and had, delivered the benefits sought in real applications. CER arranged to visit operating markets around the world to get first-hand information from market operators, participants, and regulators.
The new Irish market is consistent with the EU Directive on electricity and will facilitate a move towards an all-island market and a single European market over the coming years.
Major issues outside the market
In the consultation process CER, market participants, and others identified generation adequacy and market dominance as two very important issues outside the market trading arrangements that would have a significant impact on the new market’s success.
To address the issue of generation adequacy, Ireland opted for a primary reliance on market prices as the driver for new generation entry. Uncapped prices in a central pool market have been shown to result in new generation entry. The clearest example of this is in Australia, where the states of South Australia, Queensland, and more recently, Victoria, have experienced new entry in response to spot market prices that were capped only by a relatively high Value of Lost Load level.
Ireland has adopted a similar approach to spot market prices that reflect underlying market conditions, with these prices used to manage the short and long term actions of generators and demand. CER also has a clear expectation that sellers and buyers in the new electricity spot market will engage in active trading of financial hedge contracts and other activities to manage the resulting volatile prices.
Reflecting the high importance of a reliable system, CER will also implement a generation adequacy safety net that will be triggered ‘just in time’ to prevent capacity shortfalls should the market not deliver sufficient capacity. This ‘fast build’ safety net option will result in a new peaking station to be built and subsequently sold to the market. The option includes investment in the early development activities for this peaking plant in order to significantly reduce the lag time between the time of a decision to activate the safety net and the time that the fast-build plant is on-line and providing capacity. This approach will ensure reliability while providing a maximum amount of time for commercial decisions to be made and will minimise the distortion of incentives for new market entry.
The approach to market dominance to be used in Ireland is under development, but will rely largely on vesting contracts imposed upon the Electricity Supply Board (ESB) of Ireland. ESB has a dominant share of generation in Ireland, as it owns 80 per cent of the generation capacity in Ireland and also owns a 70 per cent share of the new 400 MW Synergen gas-fired CCGT plant. This level of generation market dominance will mean that significant measures must be taken to mitigate possible market power abuse and to alleviate the concerns of new generation entrants.
Why not NETA?
The NETA market was not implemented in Ireland, despite the proximity to the England & Wales (E&W) market and despite the familiarity of many in Ireland with NETA. Indeed, NETA was considered as one of several potential market designs for Ireland.
NETA was implemented to overcome shortcomings of the original UK pool market, despite arguments that these shortcomings might have been addressed by simply making improvements to the pool market. However, making these changes might not have produced the deep changes in the entrenched UK power market culture and practice that were delivered by NETA.
The new Irish electricity market design is most similar to that of the Singapore market. Singapore was influenced by the electricity markets in New Zealand and Australia and these were earlier influenced by the original UK pool market that was replaced by NETA.
There are some important differences between the E&W market prior to NETA and Ireland today:
- the E&W market had a surplus capacity after almost a decade of high prices, while Ireland is facing potential shortfalls
- the E&W market sought to drive wholesale market prices down after years of prices that were higher than the underlying market supply and demand would support, Ireland has no such problem
- the E&W market had little market concentration among privatised generation and retail companies, while Ireland has highly concentrated and government-owned companies
- the E&W market had a host of generators and supply companies with extensive experience in trading electricity, while Ireland has had only limited experience.
Additionally, some market design features of NETA were inappropriate for Ireland:
- NETA relies on generators and customers, none of whom have a dominant position in the market, to undertake most market activities through bilateral transactions
- NETA relies on market-organised liquid and effective forward markets to allow participants to trade out of bilateral positions, with participants establishing trading operations at a substantial cost that might not be appropriate in a smaller market
- the NETA market, effective in stimulating intense price competition in a surplus generation situation, has not yet demonstrated that it will provide timely incentives for new generation in a shortage situation
- separate spill and top-up prices in the NETA balancing mechanism, similar to the prior market in Ireland, are seen as a disincentive to renewables and small generators
- a reliance on a uniform price regime that removes locational price signals and necessitates a set of out-of-market solutions to generator location and dispatch decisions.
It is important to understand that what works well in one country or context may not be as successful in a different environment, there is no ‘one size fits all’ best electricity market design.
Any market design could work in Ireland, so long as it was well-crafted, internally consistent and reflected local conditions. The Irish market review process considered a range of market designs and options and involved a structured process to evaluate potential of the market designs to achieve the objectives for the new Irish market.
The challenge in Ireland, and in other electricity reform processes, is to design a market that will best deliver the potential benefits of markets. It is interesting to consider the market reforms in the context of the global experience. The design of electricity markets is informed greatly by the reasons why the sector is being reformed and the potential benefits that markets deliver.
Why reform the electricity sector?
The primary driver of sector reform is unhappiness with economic regulation of electric utilities. This unhappiness in present economic regulation was through government ownership or through the direct regulation of private companies. While it is possible that an effective regulatory regime or government owner could consistently achieve results that are close to the market outcomes, this has rarely been the case.
Even after decades of refining and adapting economic regulation of electric utilities, there remains a concern that economic regulation has resulted in higher prices, or rates or costs, and lower service levels than markets would have produced. There are several reasons put forward for this:
- regulated utilities may have a reduced focus on customer service and efficiency, absent the incentives, for example, loss of customers, imposed by competing in the market
- mistakes, low productivity or inefficiency by the utility usually resulted in higher prices, with few of the incentives -- higher profits -- or disciplines --lost customers -- of the market
- government owners or regulators of electricity utilities have used them to accomplish objectives that are far from their core business, such as implementing public policy, for example, assistance to lower income families, collecting taxes, and providing employment that is controlled by but not directly on the government payroll
- economic regulation has a significant flaw – operating and investment decisions are made without price signals, without the discipline of risk, with perverse incentives, and with the potential influence of special interest groups
- economic regulation sometimes even provided incentives for excess investment in assets that led to high prices
- decisions about operations and investments are made in a central planning process that sometimes made mistakes and even resulted in some spectacular failures that resulted in much higher rates for consumers.
Without the discipline of the market, the cumulative effect of these issues is higher costs, lower efficiency, and sub-optimal investments.
Why have electricity markets?
At the same time that government ownership and regulation were exhibiting unsatisfactory results, and the occasional spectacular failure, there was a re-thinking of the role that markets could play in the electricity industry. The early experience with deregulation and markets in some other formerly regulated industries — natural gas, telecoms, and transportation — generated beneficial results that stimulated interest in the reform of the electricity industry.
Industry experts and economists came to believe that the electricity industry might work better if some parts of the industry were subject to market forces and competition. In a market, operating and new investment decisions are driven by price signals and tempered by the harsh discipline of potential financial failure. The hope was that markets provide better incentives for efficient behaviour, encourage a better allocation of resources and drive appropriate investments in electricity.
Electricity industry reform is based on structural changes -- dividing the industry into two parts. The first part, primarily transmission and distribution, would remain under regulation. The second parts, retail/supply and generation, were to be deregulated and would function in the market. However, the complete reform of the deregulated bits requires an electricity market.
Electricity markets are relatively new and there are only a handful of successful operating markets in the world. These markets had a start in the competitive procurement of long-term power contracts by regulated utilities. Electricity markets now involve real-time bid-based electricity markets with features including locational pricing and co-optimised reserves. In some countries, electricity markets have transformed the power generation sector and, to a lesser extent, the retail supply sector from regulated to market-driven industries.
The benefits of electricity markets
In a competitive industry, market prices are at the supply-and-demand equilibrium, allocating resources efficiently and maximizing net benefits. Introducing markets into industries once considered natural monopolies, including electricity, has created significant and beneficial changes. Markets are acknowledged as a better way to manage the competitive parts of the electricity industry than regulation. Designing markets for electricity is an exercise in fitting a market design into the constraints present while maximising the potential for market benefits.
The benefits of markets largely arise from the self-interested actions of market participants seeking to maximize profits. A well-designed market is said to be incentive compatible’, so that the actions a participant takes to maximise profits also have the result of making the market work better and more efficiently, producing better outcomes for everyone.
A simple example is power plant output. In a functioning market, a power plant increases revenue and profits by producing more power from the same capital asset at lower costs. This increase in lower-cost power available to the market has the effect of increasing competition, lowering prices, and increasing reliability.
When a power plant operates in an electricity market, profits from that plant flow from its performance, presenting powerful economic forces. With all participants having the same incentives and taking similar actions, the result is greater industry output, lower costs, and increased reliability from the same capital investment. As the market participants compete for market share, cost-savings by producers are reflected in lower market prices that benefit consumers.
The benefits of electricity markets, compared with economic regulation, include more efficient and productive use of assets; better allocation of resources; better decisions about the type, size, fuel type, and location of new investments; innovation; and demand-side benefits.
Efficiency & gains: Operating in an electricity market leads power plant operators to reduce costs and increase output in order to increase profits. In a market, power plant owners/operators make decisions and investments that will, for example increase the reliability and flexibility of power plants, lower fuel costs, renegotiate fuel contracts or add on-site storage, increase efficiency, such as upgrade turbines to take advantage of new high-combustion-temperature blades that raise thermal efficiency and reduce other costs.
Resource allocation: In a market, the most efficient and productive power plants will take a larger market share, with less efficient power plants taking a smaller share. One result might be that inefficient or costly power plants will not generate sufficient profits to cover fixed operating costs and will be shut down, with the sites used for new, more efficient and productive generating plants. Another result will be that the least expensive fuels will result in lower costs and will displace higher cost and higher value fuels.
Investment Efficiency: The largest source of benefits from electricity markets is likely to be investment in new plant. In an electricity market, an investor has to have confidence that the investment will earn a return, otherwise the money goes to more attractive investments. While getting a return in the generation business is not simple, an astute analyst will see opportunities for profit in:
- a system with relatively high prices in all hours that might provide good returns to a new power plant with marginal costs below most competitors. Such a power plant might operate as a base load unit, pushing older, less efficient power plants up the merit order
- a system with spiky load and prices that might be an ideal place to build a very low capital cost, low efficiency peaking unit that runs only a few hours a year at high prices (or provides hedge contracts to others in the market concerned about price spikes)
- a particular location that might have a shortage of power that makes locational prices there higher and more attractive to an investor in a new power plant. Appropriate power plant location decisions might also have the effect of relieving transmission constraints and reducing the need for transmission investment.
A range of other options for types of power plants, fuel sources, size of plant, locations, and other factors will be considered as investors seek to find profitable niches. If the market is designed well and there is minimal intervention, investment will ensure that efficient system expansion takes place, with no need for central generation expansion planning.
Innovation: Many improvements in operational efficiency, resource allocation, and investment efficiency derive from innovations that have been developed and implemented by participants. Without the motivations of profit, many of these innovations might not exist or might not quickly come to market. Examples include gas turbines with very high thermal efficiency; the use of gas-turbine technology in a combined-cycle mode; and a variety of small cogeneration and distributed generation technology, for example, micro-turbines).
Owners of existing generation plants have, under market incentives, made modifications to allow power plants to operate at higher maximum output levels, to operate at lower minimum output levels; have shorter start-up times and shorter minimum downtimes; to change output levels more rapidly; and otherwise increase the power plant’s ability to profit from market operation.
There are also benefits from the demand side of the market. The presence of market prices for electricity, especially if these prices are real-time and locational, will provide customers with strong price signals. Even less complex or timely prices will provide more price signals than earlier regulation. There is evidence that electricity consumers are fairly responsive to changes in prices and even to opportunities to make profits from the market, for example, New Zealand interruptible load has become the primary source of operating reserves at a fraction of the cost of providing the same level of reserves from power plants.
Conclusion
The new Irish electricity market has adopted a proven design that is expected to deliver benefits. This design has been tailored to the situation in Ireland and will be further adjusted through additional consultation on market details. The Irish market may well become a viable new paradigm for Europe.
