ELECTRICAL INDUSTRY RESTRUCTURING

Is Ontario's Electricity Market Working?

Ontario's wholesale electricity market has been open to competition for three months and the lights are still on. So, it's working. But is it working well? How do we know? Most consumers who have checked market energy prices posted by the Ontario's Independent Market Operator (IMO) (www.theimo.com), as shown in Figures 1 and 2 probably feel the market is operating well, because prices have on average, been relatively soft.

SIGNS OF MARKET PERFORMANCE [1]

Given the characteristics of wholesale electricity markets in general and the unique structure of Ontario's market in particular, standard economic tests to evaluate the performance of markets may be unreliable. However, there are measures that can be applied to electricity markets as indicators of market performance. Here we will examine three of these: apparent bidding behaviour, price differentials between Ontario and its competitive interconnected markets, and timing and volumes of imports and exports across the interconnections.

Bidding Behaviour

In an ideal, fully competitive electricity market with 1) an abundance of capacity, 2) many suppliers, 3) open transmission access, and 4) an uncongested transmission system, baseload generators would offer energy at their incremental cost of production. In a competitive market, generators will assume that they will not be setting the market-clearing price that is paid to all suppliers. To bid more than their incremental cost of production reduces the chance that the baseload generator will be dispatched, but would not be expected to increase the dispatch price. Generators with peaking resources, on the other hand, will be likely to mark up their marginal cost based bids to ensure that they are able to cover their fixed costs over the limited number of hours that they run. Hydro-electric generators with storage capacity have a more complex decision. At any point in time, their offer would need to reflect the future value of the energy stored in the reservoir - they can use it now (if their bid is accepted) or use it later when prices might be higher - and their expectations of additional flow into their reservoir.

Given a good understanding of the Ontario supply stack (each generating unit's size and marginal cost), the planned outage schedule (which units will not be available and when), and monitoring other dynamic variables such as forced outages and hydroelectric storage levels and expected rainfall, one can attempt to 'predict' the market clearing price for any given system demand. This market-clearing price is simply the point of intersection between the supply and demand curves. A comparison of this predicted market-clearing price can then be made with actual demand-price pairs experienced in the marketplace. Demand-price pairs for each hour from May 1 to July 23 relative to our illustrative supply stack are shown in Figure 3.[2]

Based on our market analysis, it appears that actual prices have closely tracked the expected marginal costs of generation for demand levels up to approximately 18,000 MW (these are primarily off-peak hours). This suggests that generators have been offering energy at prices quite close to their marginal costs, an indication that the market is performing as one would expect under workable competition. When market demand exceeds 18,000 MW or so, the price-demand pairs exhibit much lower correlation with our predicted supply curve. This can be attributed to the storage hydroelectric generation offer strategies that are priced on the basis of opportunity costs and are likely to be reflective of prices in interconnected markets. In addition, at these higher demand levels forced outages of generators can result in sudden increases in the need for available generation. This can produce dramatically higher market prices for short time intervals and results from generator ramping rate restrictions and the relatively short time interval over which dispatch is optimized. Therefore, when there is a shortfall in generation as a result of an unscheduled generator outage or higher demand than forecast, significantly higher cost generation must be called on to provide energy while lower cost resources are ramping up.

Influence of Interconnected Markets

Two additional indicators one can use to test a market's functionality are: the relationship between the local market price and prices in interconnected markets, and power flows across interties in relation to the prices. In an 'ideal' regional electricity market with unlimited transfer capabilities between regions, there would be one price throughout the market. This is in fact how economists define markets, i.e., based on the absence or presence of significant price differentials. In reality however, there are always some physical limits to the transmission capacity between regions and, to the degree that these constraints are significant, they are likely to define the market. Although Ontario is physically connected to Minnesota, Manitoba, Michigan, and Quebec, we look to the New York ISO, because it is the most transparent of Ontario's interconnected markets and a market with which Ontario has significant transfer capability such that price differentials should be minimized. Ontario is connected to New York at two locations. The larger is at Niagara Falls which connects Ontario with the New York West or NY Zone-A market. This interconnect has an export capacity of approximately 2100 MW (to New York) and an import capacity of approximately 1500 MW (into Ontario). The other interconnection with New York is near Cornwall, but the capacity of this interconnect is only 400 MW. Figure 4 shows the Ontario and New York West hourly energy prices for the period from May 1 to July 23. For most hours, the Ontario hourly energy price (HOEP) closely tracks that in New York West. During price excursions (spikes), differentials are seen for various reasons including the inability to change import and export schedules within the hour and the fact that these price excursions are often the result of unplanned generator outages and thus are short-lived, i.e., until additional low-cost generating capacity can be scheduled to fill the deficit.

Initially, interties were developed primarily for system reliability purposes. In competitive markets, interties continue to play an important role in system reliability, but serve another important purpose. Interties allow trading between markets, which enables traders within interconnected markets to arbitrage price differentials. With sufficient transmission and flexible market rules, the net effect is that the lowest cost generation is available to serve load in these markets. One would expect that in a workably competitive market, New York would be importing power when the prices in New York are higher than those in Ontario, and vice versa. Figure 5 shows pricing differentials and transmission flows between Ontario and New York West for May.

Because the power flows shown in the figure include flows to and from New York Zone A and Zone D (the IMO doesn't publish data for transmission flows from New York Zone A and Zone D separately), the results shown in Figure 5 are more difficult to interpret. Overall, however, the chart suggests that power generally flows from New York to Ontario whenever the Ontario price is lower than the New York price and vice versa, as one would expect in an effective regional market.

Market Issues

Probably the most contentious market design issue that has arisen thus far is from the market rule pertaining to intertie transactions.

Once import offers are accepted by the IMO based on a similar offer process as is used for internal Ontario generation ,the quantity and minimum price of these imports are set and remain constant for the hour. This is because intertie schedules cannot change within the hour. This is called the import offer guarantee (IOG). Simply, if the IMO expects that imported energy will be required to meet Ontario demand for the next hour, the importer is guaranteed of being paid at least his offer price regardless of what actually happens during the hour. Thus, importers are guaranteed their accepted offer for the full hour, even if demand drops off or increased amounts of supply are available at lower offer prices and as a result their energy is not needed. In contrast, Ontario-based generators must offer energy into the five-minute energy market [3] and the IMO can respond dynamically to their offers based on actual system demand and supply.

In a simplified example of how this rule would work, if the IMO needs 25,000 MW of supply to meet demand on a hot day and Ontario-based generation can supply 23,000 MW, the IMO would need to import 2,000 MW from outside Ontario. If the offer for this imported power is higher than the most expensive power from among the various Ontario-based generators comprising the 23,000 MW of 'native supply', the IMO would set the five-minute price based on the most expensive of the Ontario offers, not on the 2,000 MW of imports needed to match demand. The IMO would still have to pay for the 2,000 MW of imports, but the cost of this power would not be reflected in the market-clearing price.

The cost of any imported power, subject these rules, is borne by all consumers through the IMO uplift charges, not through spot prices. Although uplift charges have typically been in the range of $1-$5/MWh, during periods of high demand, hourly uplift charges have exceeded $100/MWh, largely as a result of these two rules. What is important to bear in mind is that during these infrequent periods when uplift charges are high, market-clearing prices could have been much higher in the absence of these market rules.

From a consumer perspective, these rules have helped to dampen the volatility of spot prices. From an Ontario generator's perspective, these rules have reduced revenues and could ultimately deter new generators from entering the Ontario market.

Lower price volatility and less extreme price spikes should be good news for most consumers. However, consumers that locked into a fixed price contract in an effort to mitigate their price risk may be disappointed to learn that they are still exposed to volatility in uplift charges, which (to our knowledge) are not covered in any electricity contracts. Thus, while these market rules dampen spot price volatility, they create new risks which suppliers have not yet been able to offer consumers protection from. It is probably only a matter of time before someone offers 'uplift charge' guarantees.

Summary

The Ontario electricity market, although just three months old, appears to be working reasonably well. Prices in many hours have been closely related to the underlying marginal costs of generation, prices in Ontario and New York have tracked well most of the time, and power flows between New York and Ontario are generally responding to any price differentials between the markets.

The primary market performance issues appear to be related to market rules and how imports are integrated into the market. Changes to these rules could have a significant impact on the volatility of spot prices, particularly during periods of high demand, as well as on the relative attractiveness of the Ontario market for new generators.

References

[1] In economics parlance, workable competition is used to characterize a market that is less than perfectly competitive. This review does not offer an opinion on the competitiveness of the Ontario wholesale power market.
[2] This supply stack is dynamic and changes with load and general market conditions. The supply stack would contract during shoulder periods as generators schedule maintenance, and expand during peak periods as generators attempt to ensure availability to capitalize on higher market prices.
[3] Typically consumers refer to the hourly energy price, but in the wholesale market, energy is traded in five-minute intervals.

Jonathan Dickman-Wilkes is a Senior Consultant with Navigant Consulting, North America's largest energy-focused management consulting firm. Jonathan has an Engineering Degree from the University of Waterloo.

Navigant Consulting offers energy consulting services to all entities that play major roles in electricity and gas markets. Navigant Consulting has recently completed its Summer 2002 Ontario Electricity Market Assessment and Price Forecast, which is available as an off-the-shelf consulting study. This study has been used by large users to evaluate power purchases as well as by generators to evaluate large and small generation project economics.

You can contact Jonathan at jdickman@navigantconsulting.com or at 416 927-1641. ET