Ireland has selected and is implementing a new electricity market that is not, as many expected it might be, a carbon copy of either NETA or SMD. Instead, this new market resembles the market in Singapore - the result of a market review process aimed at realizing electricity market benefits. The market review and design process in Ireland, and the thinking behind it, may offer insights for the US and other countries.
Introduction
Ireland has selected a new electricity market design. The Commission for Energy Regulation (CER) is now implementing this new electricity market, referred to as Margadh Aibhléise na hÉireann or MAE.
The MAE is not, as many expected it might be, a carbon copy of either NETA or SMD. Instead, this new market builds on the proven design of the Singapore electricity market. This outcome was the result of a market review process that was aimed at realizing the benefits that electricity markets can offer. The market review and design process in Ireland, and the thinking behind this process, may offer insights for the US and other countries.
Ireland implemented an interim market in early 2000, with an explicit provision that the interim trading arrangements would be reviewed in 2004. CER decided to start this review in 2002 and to agree on high level market principles in early 2003. The review was accelerated to allow time to implement the new electricity trading arrangements; to provide existing market participants more time to understand and adapt to the new market; and to reflect the long lead time between planning and executing new generation projects.
CER sought trading arrangements that would best meet its primary objective – delivering an efficient level of sustainable prices to all customers with a supply that is reliable and secure in both the short and long-run.
As the US experience shows, clear apportionment of responsibility and authority is important in electricity sector reform. CER, as the independent energy sector regulator, was given authority to undertake the design and implementation of the new electricity market. While CER does not have the authority to undertake industry structural changes, CER does have the authority and responsibility to fashion measures to address the market dominance issues presented by the large incumbent utility, the Electricity Supply Board (ESB).
One of the primary drivers of electricity sector reform in Ireland is the EU Electricity Directive. Ireland’s membership in the EU has been very positive and Ireland seeks to be a leader in electricity reform in Europe.
Electricity market details
The new market design selected for Ireland is a mandatory centralized pool with locational marginal pricing, reflecting transmission losses, constraints and ancillary services, calculated in each half hour of the day.
In the near real-time spot market, all electricity will be sold to and bought from the System and Market Operator (SMO). The spot market will be cleared and corresponding dispatch schedules determined simultaneously for each half hour trading interval. Each separate dispatchable generator will provide price and quantity offers for each trading interval and may change these offers as often as they choose up to gate closure. Suppliers (ie retailers) may elect for their load to be classified as dispatchable or non-dispatchable. For dispatchable load, suppliers will provide price and quantity bids for each trading interval and may change these bids as often as they chose up to gate closure. All remaining non-dispatchable load will be estimated by the SMO. After gate closure, bids and offers will be binding except in exceptional circumstances.
The market will provide no explicit separate payments for capacity, a model sometimes referred to as an ‘energy-only’ electricity market.
The market clearing price for each node will be the locational marginal price (LMP) at that node. This price will be the market cost of the last unit of electricity injected or withdrawn at that node. The SMO will simultaneously resolve system feasibility and market dispatch and in so doing will take into account losses, transmission constraints, reserve requirements and other relevant system security constraints when determining dispatch schedule and when setting LMPs. LMPs will be set immediately prior the beginning of each trading interval in advance of real time dispatch. These prices may be positive or negative and will limited to plus or minus the Value of Lost Load (VoLL), currently set at €7,200 per MWh.
Generators will make sales at the LMP associated with their location, while suppliers/retailers will make purchases at a single load-weighted average price of the locational prices (the Uniform Purchase Price) regardless of location.
Settlement will be made at actual metered volumes during each half-hour trading interval. The SMO will produce week-ahead and day-ahead pre-dispatch runs that will indicate the projected spot market prices and generator dispatch schedules prior to actual dispatch.
The market will include Financial Transmission Rights (FTRs) to hedge the risk of locational marginal price differences.
Participants are expected and encouraged to enter into negotiated hedge agreements with each other (eg contracts for differences or CfDs) in order to manage the financial risk presented by spot market prices. The participants, not the SMO, will settle these hedge agreements. A part of the market power mitigation measures will include imposed hedge contracts (ie vesting contracts) that will also help establish the hedge contract market and ensure financial stability in the transition to a market.
The SMO will purchase reserves, and implement, as appropriate, a market for appropriate reserve products that is co-optimized with the electricity spot market. Reserve providers may include both generators and demand customers.
Co-optimized reserve and energy markets involve the simultaneous determination of a price for electricity and a price for each category of reserve. The electricity price reflects the marginal cost of supplying an increase in load and equals the cost of generating more electricity while respecting the reserve requirements. Similarly, the price in each reserve category reflects the marginal cost of that type of reserve, with this marginal cost equal to the sum of the marginal producer’s bid to providing one more unit of reserve and the marginal opportunity cost incurred in backing off electricity generation to provide reserves.
This approach means the marginal reserve provider is compensated by the reserve price for the lost opportunity to make profits in the electricity market. Reserve providers that are not the marginal provider will make additional profits; just as infra-marginal energy providers do in the energy market.
The simultaneous scheduling of electricity and reserve in this manner achieves a highly efficient dispatch for both energy and reserves that ensures adequate reserve is available and provides long-run signals for market responses to reserve shortages.
The experience in other markets strongly suggests that such an approach has been successful, not only in terms of ensuring provision of reserve, but in reducing the overall cost of reserve provision. Innovation in the development of interruptible load as a substitute for traditional spinning reserve has also been an outcome of this approach, both lowering the cost of reserves and reducing the overall requirement for generation capacity.
Potential for an all-island market
Northern Ireland remains a separate jurisdiction with its own electricity market. While there is considerable interest in having a single electricity market for the entire island based on the MAE, this is not yet agreed.
One benefit of the market design selected for Ireland was that is easily extended to include Northern Ireland. The problems of customer rate differentials when markets are combined can be addressed by having a different uniform price in each jurisdiction for customers (both composed of weighted average LMPs, but across the two different geographies), while generators see a single all-island integrated LMP market.
In the period prior to any single all island market, there are important interconnection and seams issues to address. These issues are currently the subjects of a market consultation.
There are three physical grid connections between Ireland and Northern Ireland. The main interconnector (the North-South Interconnector) is a set of two 300 MW AC lines that is used for inter-regional trading. There are also two smaller 110 kV connections in the northwest that are normally only used in the event of a loss of both North-South Interconnector lines.
OFREG, the Northern Ireland regulator, is currently assessing whether it would be beneficial to Northern Ireland to join the new Irish electricity market. If Northern Ireland were to adopt the same trading regime and form a single all-island market then the need for interconnector trading between the two jurisdictions would disappear.
Major issues outside the trading arrangements
The consultation process 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.
Generation adequacy
The new Irish market will rely on market prices and market entry to provide an adequate level of generation and reliability. Uncapped prices in a central pool market have been shown to result in new generation entry. The clearest examples of this are in Australia, where the states of South Australia, Queensland, and more recently, Victoria, have experienced new entry in response to uncapped spot market prices with no separate capacity mechanism.
Ireland has adopted a similar approach, with spot market prices that reflect underlying market conditions used to manage the short-term (eg dispatch and unit commitment) and long-term (eg new entry) actions of generators and demand. CER has a clear expectation that sellers and buyers in the new electricity spot market will engage in active trading of financial hedge contracts and in other activities to manage the resulting volatile prices. The resulting bilateral hedge contract market will provide additional input to generator investment decisions, as has been the case in Australia.
Reflecting the high importance of a reliable system, CER also designed a generation adequacy safety net that will be triggered just in time to prevent capacity shortfalls should the market not deliver sufficient capacity.
This safety net approach, referred to as the “fast build” option, involves a new peaking station that will be built, placed in operation and subsequently sold in the market. The option includes investment in the early development activities for this peaking plant in order to significantly reduce the period 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 new entry decisions to be made and will minimize the distortion of incentives for new market entry through a combination of short time to build, well-defined trigger conditions and use of only peaking stations.
Dominance
ESB has a dominant share of generation in Ireland, owning outright 80 percent of the generation capacity in Ireland and holding a 70 percent share of the new 400 MW Synergen gas-fired CCGT plant. This level of generation market dominance, if unchanged by any structural changes, will mean that significant measures must be taken to mitigate possible market power abuse and to alleviate the concerns of new generation entrants.
The approach to market dominance to be used in Ireland is currently under development, but will rely on vesting contracts imposed upon ESB plus a range of regulatory requirements and oversight. The details of these arrangements are still being developed and will reflect the extent of structural changes to ESB undertaken by the responsible Minister. The goal will be for ESB to mimic the behavior of a competitive participant.
The new Irish market is not NETA or SMD
While some industry observers in the UK or in the US expected that Ireland would adopt the market models in those countries (ie NETA and SMD), this did not happen. Some specific features of these two markets were viewed as inappropriate for Ireland.
NETA raised concerns because it may not provide timely incentives for new generation in a shortage situation; because it has separate spill and top-up prices that are seen as a disincentive to renewables and small generators; and because of a uniform price regime that creates a need for out-of-market solutions to transmission congestion and generator dispatch.
SMD raised concerns because it anticipates that spot market prices will be subject to regulatory control or price caps (an unfortunate legacy of the California crisis), with these caps creating the need for complicated capacity mechanisms to ensure generation adequacy.
The new Irish electricity market design is most similar to that of the Singapore market. The Singapore electricity market was influenced by the electricity markets in New Zealand and Australia. New Zealand and Australia were, in turn, influenced by the original UK pool market that was replaced by NETA.
A range of options for the Irish electricity market was developed, ranging from a return to regulation to a decentralized market. The team assessed these options (and a variety of sub-options) on five key criteria: efficiency, equity, environment, stability and practicality. The option chosen had to send the right price signals to balance supply and demand in the short term and long-term; produce sustainable pricing in the wholesale market; and reflect specific constraints in Ireland, CER objectives and Irish government policy.
The evaluation process revealed a preference for the ‘centralized market’ option, as described above.
How to think about electricity markets
Any electricity market design could work in Ireland, so long as it was well crafted, internally consistent and reflected local conditions. However, it is important to understand that what works well in one country or context may not be as successful in a different environment.
The challenge in Ireland, and in other electricity reform processes, is to design a market that will best deliver the potential benefits of markets. 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. Behind this process was an examination of the reasons why the electricity sector is being reformed and the potential benefits that markets deliver – in order to focus the effort on achieving these benefits.
Electricity sector reform has a purpose
The primary driver of electricity sector reform is unhappiness with economic regulation of electric utilities, whether through government ownership or through the 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 results in higher prices and lower service levels than markets would have produced. This is, among other things, because:
· regulated utilities have a reduced focus on customer service, productivity, and efficiency without the incentives (eg higher profits) and disciplines (eg loss of customers) imposed by a functioning market
· operating and investment decisions are made without price signals, without the discipline of risk, sometimes with perverse incentives, and with the potential influence of special interest groups
· government owners or regulators of electricity utilities have used them to accomplish various objectives that are far from the core electricity business.
Without the discipline of the market, the cumulative effect is higher costs, lower efficiency, and sub-optimal investments. Electricity markets can provide benefits
Electricity industry reform is based on structural changes, with the industry is divided into transmission and distribution, that remain regulated, and retail/supply and generation, that are deregulated. The deregulated parts require an electricity market.
In a market, operating and new investment decisions are driven by price signals and tempered by the harsh discipline of potential financial failure. Markets can provide better incentives for efficient behavior, encourage a better allocation of resources and drive appropriate investments in electricity.
In some countries, electricity markets have effectively transformed power generation and, to a lesser extent, retail supply into market-driven industries. 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, if done well, are a better way to manage the competitive parts of the electricity industry than regulation.
The benefits of markets largely arise from the self-interested actions of market participants seeking to maximize profits. Well-designed markets are “incentive compatible,” so that participant actions to maximize profits also have the result of making the market work better and more efficiently, producing better overall outcomes.
When all participants have the same incentives and take similar actions, the result is greater industry output, lower costs, and increased reliability from the same capital investment. As market participants compete for market share, cost-savings by producers are reflected in lower market prices to consumers.
Designing markets for electricity is an exercise in fitting a market design into constraints while maximizing the potential for market benefits.
The benefits of electricity markets, as compared with economic regulation, include more efficient investment, more efficient and productive use of assets: better allocation of resources, innovation and demand-side benefits.
Investment efficiency
The largest source of benefits from electricity markets is likely to be in the area of investment in new power plants, even though these benefits may not appear for years. A range of options for power plant type, fuel source, size of plant, location and other factors will be considered as investors seek to find profitable niches. If the market is designed well and there is minimal intervention, market investment driven by prices should ensure that that there is no need for central generation expansion planning.
In an electricity market, an investor must have confidence that the investment will earn a return. While getting a return in the generation business is not a simple matter, an astute analyst will see opportunities for profitable investments with prices being the primary indicator of these opportunities.
Operational efficiency and productivity 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 increase the reliability and flexibility of power plants, lower fuel costs (eg renegotiate fuel contracts or add on-site storage), increase efficiency (eg upgrade turbines to raise thermal efficiency) and reduce other costs.
Resource allocation
In a market, the most efficient and productive power plants will take a larger share of the market, 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.
Innovation
Many improvements in operational efficiency, resource allocation, and investment efficiency derive from innovations that have been developed and implemented by market participants. Absent 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 (eg micro-turbines).
Owners of existing generation plants, when moving from regulation to markets, have made modifications to increase maximum output levels, decrease minimum output levels; shorten start-up times and shorten minimum downtimes; increase ramp rates; and otherwise increase the power plant’s ability to profit from market operation.
Demand-side benefits
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. There is significant evidence that electricity consumers are fairly responsive to changes in electricity prices and to opportunities to make profits from the market (eg in New Zealand interruptible load has become the primary source of operating reserves at a fraction of the cost of reserves from power plants).
Regulatory intervention can reduce benefits
The Irish market is designed to minimize regulatory intervention and to constrain this intervention to well-defined areas.
To maximize benefits, markets should be designed to operate with only minimal controls and regulation. Unhappily, there are large differences of opinion on the level and type of control and intervention that is necessary for electricity markets. This difference may reflect the deep divide between those that believe that markets can work in electricity and those that believe that markets cannot and will not work in electricity.
In some countries, the belief that markets will work in electricity leads to less intrusive and minimal regulatory intervention, with the ultimate aim of electricity markets with little or no regulatory intervention.
In other countries, the belief that markets will not work in electricity leads to an ever-increasing level of regulatory intervention with an ultimate goal that seems to be regulated outcomes from the “market.” When a market is highly regulated or controlled, the outcomes will be different, and probably worse, than the outcomes from a functioning market. Indeed, a highly regulated electricity market could result in outcomes (prices, reliability, efficiency and productivity) that are worse than those in a well regulated vertically integrated electricity industry.
The US, with a long history of economic regulation of privately owned electric utilities, seems to be more comfortable with regulatory intervention in electricity markets than countries without this long tradition and practice of regulation. Perhaps because of many decades of cost-based prices for electricity, many in the US seem uncomfortable with and opposed to the concept of market prices in electricity.
It is troubling is that the ultimate impact of regulatory intervention (or the lack of it) may not be obvious for some time. Price caps that seem harmless and even beneficial in the short term may have a negative impact on the level, type, and timing of new entry or on the level of reliability that will not be seen for years.
Proven designs reduce risk and increase benefits
Electricity market design experience is growing. A decade ago, when electricity markets were very new and even experimental, it was perhaps appropriate for each market to develop its own unique design. Today, there are many examples of entire market designs that work (or do not work) and an even greater number of market design features that work (or that have not worked).
In another decade, electricity market design may be at a stage where a single design approach dominates and some of the current “experiments” in market design will be recognized as evolutionary dead ends.
One must look beyond national or regional borders to get a full understanding of the available experience in market designs and market design features. However, looking at other markets for proven designs and design features must be done with a realistic assessment of the environment that is present in the local market and in other markets.
CER undertook a comprehensive review of market designs and made visits to electricity markets in the US, Europe and Asia-Pacific. The process was aimed at lowering risk and cost by focusing on proven approaches and designs where possible.
Effective consultation to enhance buy-in
CER undertook extensive (and successful) consultation with market participants and other stakeholders in the market review, including tutorials aimed at explaining complex and new market concepts so that a more effective discussion of the issues could take place.
In the market review, Ireland defined the objectives for the new Irish market, defined several internally consistent market approaches, and then evaluated these approaches. Throughout this process, actual experience in markets that were similar to Ireland was examined to find features that were tested and proven in practice 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 comprehensive and intense consultation and education process in Ireland reflected the reality that electricity reform presents special problems in consultation and communication. The pervasive use of electricity, implicitly high expectations of reliability and availability, the close interest and involvement of government, and the presence of extraordinarily complex issues make broad discussion of electricity market reform issues difficult.
Most people use electricity, even though they understand little about the industry and how it works. These people expect a highly reliable supply of electricity at relatively low cost, with little understanding of the relationship between reliability and cost. When a switch is thrown, electricity is expected to be available and when the monthly bill comes, it better not be too high.
Because of the pervasive use of electricity and the long history of regulation and government involvement in the sector, the government is highly interested in the price and reliability of electricity. Even if markets effectively transform the electricity sector, the government is likely to be the first stop for those with complaints.
Few people have any real understanding of the complicated nature of the electricity system, and even fewer people have a good working knowledge of the issues, details, and implications of electricity markets.
This lack of knowledge, coupled with the relative newness of electricity markets, means that many differing views may be seen as credible. It is possible to present different and even contradictory points of view, all of which sound quite credible. The recent US blackout was, for example, used to validate almost every vested interest in the industry. The ability to craft a clever headline and tell a seemingly simple story may be more important than the validity of the message.
Accordingly, there is a need in the electricity reform process for education and a well-informed referee that does not have a vested interest.
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 new paradigm for Europe and elsewhere.
