ELECTRICITY RESTRUCTURING

Report on Restructuring of the Canadian Electricity Industry

In the traditional market structure of the electricity industry, generation, transmission and distribution of electricity are owned and managed by vertically-integrated monopolies. This form of market structure, which still prevails in much of Canada today, was widely adopted because the electricity supply industry was regarded as a natural monopoly. With respect to generation, this meant that lowest costs could be achieved by building large scale power plants. The nature of long-distance transmission systems and local distribution systems also fit the natural monopoly model. Even if competition were possible in generation, it would still not be economically feasible to build competing transmission and distribution facilities to serve the same market, i.e., lowest costs would be achieved by one facility.

Because of the concern that monopolies would be able to exercise market power, their operations were either overseen by regulatory bodies acting in the public interest or, in the case of most Canadian provinces, public ownership was established in the form of Crown corporations.

The utilities in each province tended to develop their own generation, transmission and distribution systems consistent with provincial energy requirements. In addition, interprovincial and international transmission ties were made to achieve anticipated benefits such as:

• cost savings due to lower installed reserve requirements;
• the ability to install larger, more economical generating units;
• seasonal diversity and economy energy exchanges;
• the ability to enter into firm power contracts; and
• other anticipated benefits such as service reliability and emergency assistance.

1. Technological advances in generation made the construction of smaller gas-fired generating units feasible, particularly combined-cycle natural gas turbines. These units can provide incremental supply at lower capital costs, and can be built more quickly than conventional fossil fuel or nuclear plants. At the same time, it was profitable for industrial electricity consumers to purchase natural gas to simultaneously produce process heat and electricity (cogeneration) and to sell any surplus electricity into the electricity grid.
2. Many jurisdictions, for example in the U.S. Northeast and California, took the view that access to a utility's transmission lines should be made available to other service providers to provide access to cheaper supplies from neighbouring regions, and regions further afield. This would require obtaining non-discriminatory access to transmission systems.
3. Experience with deregulation and restructuring in other industries such as telecommunications, natural gas and the airlines suggested that competition between producers and service providers would lower costs and provide a broader selection of services to consumers.

Two essential aspects of restructuring are wholesale access and retail access. Wholesale access refers to generators having the ability to obtain access to transmission systems to compete in for wholesale markets, which may include distribution companies or independent marketers. Retail access refers to marketers having the ability to obtain access to distribution systems to sell to end-use consumers, and conversely, allowing end-use consumers a choice among marketers. Full retail access occurs when all end-use consumers have this choice. Wholesale access can occur without retail access; however, retail access requires wholesale access.

Restructuring Initiatives
In Canada, the movement toward restructuring the electricity industry has been uneven, as each province assesses its own unique regional circumstances and issues. Alberta restructured its electricity market over a five-year period culminating in full retail access on January 1, 2001. Ontario plans to implement full retail access in May 2002.

Most other provinces, including New Brunswick, Québec, Manitoba, Saskatchewan, and B. C. have implemented, or are planning to implement, wholesale access. Aside from Ontario and Alberta, no other provinces are planning to implement full retail access.

In the U.S., competition in generation was introduced when the Public Utilities Regulatory Policy Act was passed in 1979. This allowed, under various restrictions, independent power producers to sell into wholesale markets, thus ending utility monopoly over generation. Significant legislation emerged in the Energy Policy Act of 1992 . This act mandated the U.S. Federal Regulatory Commission (FERC) to implement open access to transmission systems and eventually resulted in FERC Order 888 (1996). The order requires that "transmission customers of jurisdictional utilities who take service under the open access tariff and who own, control, or operate transmission facilities must, in turn, provide open access service to the transmitting utility." Order 888 has implications for Canadian electricity exporters. It effectively requires that Canadian transmission companies provide U.S. marketers access to their transmission facilities so that Canadian exporters utilizing those facilities, and open access systems in the U.S., may obtain a licence from FERC to market electricity in U.S. wholesale markets. This is referred to as the reciprocity requirement of Order 888.

Most recently, to further facilitate competitive wholesale markets, FERC Order 2000 (December 1999) required transmission companies under FERC jurisdiction to form Regional Transmission Organizations (RTOs) by December 2001, and defined the characteristics and functions that qualify an RTO. In view of the interconnections between U.S. and Canadian transmission systems, FERC encouraged Canadian participation. In Canada, the tariffs of electricity transmission systems are in the purview of the provinces. Thus the NEB does not have FERC-like jurisdiction.

While FERC regulates interstate transmission and has a mandate to ensure that consumers have access to electricity at fair and reasonable rates, retail access is largely the responsibility of individual states. As of mid-2000, approximately 21 percent of U.S. electricity customers had retail access; however, less than one percent, accounting for 1. 5 percent of load, have exercised the option. The reason for the low participation is that, to date, the new marketers have not been able to compete successfully with the incumbent utilities.

In addition to the initiatives undertaken in Canada and the U.S., restructuring of the electricity industry has been underway in several other countries during the past decade. In Australia, New Zealand and the United Kingdom this required the unbundling of government-owned monopolies.

Restructuring Issues
Stranded Costs and Benefits
An initial concern regarding the restructuring of electricity markets was that some generating plants would not be economic in a competitive environment and that they would become 'stranded' from the system. Consequently, their market value would be below book value, resulting in potentially large losses for the utilities owning these plants. The issue arose as to how these costs would be recovered.

In Ontario, the outstanding debt from Ontario Hydro has been referred to as a stranded cost. The debt is being managed by a successor company to Ontario Hydro and will be recovered from Ontario electricity customers based on consumption.

In the U.S., stranded costs were associated with some nuclear facilities and older, less-efficient fossil fuel plants. Various ways have been designed to recover stranded costs, such as securitization and direct recovery through transition charges on electricity transmission and distribution.

Overall, as events have unfolded in the U.S., stranded costs have not been an impediment to restructuring. Initially, many utilities expected they would face burdensome stranded debt that they might not be able to recover, either because of market conditions or because some states would not allow these costs to be passed on to consumers. In fact, state regulators have allowed for full recovery and, because prices in bulk power markets have been stronger than anticipated, prices have tended to support higher values for these assets.

Stranded benefits can occur when the market value of divested assets is greater than the book value. In Alberta's restructuring scheme, a stranded benefit was associated with older generating plants. The value was established at auctions that sold the rights to market the power from these plants. The residual value between the prices bid for the power and the cost of operating the plants is being returned to Alberta consumers in the form of deductions from their monthly electricity bills.

Market Power
When considering restructuring for their respective jurisdictions, regulators have been concerned that market power might be exercised in some segments of the electricity market. For example, generators that own substantial amounts of capacity (province-wide or at strategic locations) could be in a position to prevent competing suppliers from entering a particular marketplace. Transmission facility owners might be able to withhold transmission access from competitive generators. In a restructured environment, incumbent distribution utilities may be in a position to take greater advantage of new market opportunities than their competitors because they have better access to customer information.

Ontario and Alberta have each taken steps to mitigate market power. In Ontario, the Market Power Mitigation Agreement established Ontario Power Generation's licence conditions and an Independent Market Operator has been established to assure non-discriminatory access to transmission.

Alberta's ap-proach to mitigate market power includes the creation of an independent power pool and an independent transmission administrator, as well as the auctions of power plant output to reduce the market share of incumbent generators.

Reliability
Traditionally, electric generating utilities operated with high reserve margins, often in the range of 20 to 25 percent above peak demand. This was deemed necessary and prudent because of potential unscheduled plant outages. In restructured markets operating margins tend to be lower; therefore, other things being equal, the prospects of supply disruptions are greater, although costs are lower.

With the unbundling of the generation, transmission and distribution functions, reliability becomes more of a shared responsibility between these entities and is reflected in their tariff provisions (terms of service).

Marginal Cost versus Average Cost Pricing
In the traditional market structure electricity prices are established by average cost pricing. Average cost pricing reflects a regulated generator's approved costs for less expensive and more expensive supply sources.

In restructured markets, where there is competition among generators, prices are based on market forces. Buyers and sellers can be brought together to settle a price in a number of ways. One way is a negotiated bilateral arrangement between a generator and a buyer. Another is the formation of a power pool where many buyers and sellers interact to establish the market price.

The power pool approach as adopted in Alberta and contemplated for Ontario employs marginal cost pricing, i.e., the pool price is set by the cost of the last unit of supply required to meet market demand.

An important point about marginal cost pricing is that all producers receive the same price even though their own costs may be lower and they might even have offered supply into the pool at a substantially lower price. This means that, all else being equal, when marginal costs are greater than average costs, the market price will be higher in the restructured environment.

If prices generally equate to marginal costs, prices will change to match the marginal cost of generation, and thus spot prices could be quite volatile. However, prices need not always reflect marginal costs. If the regulatory regime permits, buyers and sellers may negotiate bilateral arrangements for volume, price and time period. Depending on market conditions, the pricing terms could be less than the marginal cost. A well developed forward market, where standardized contracts for the future delivery of electricity are traded according to established rules and regulations, would also provide a similar price risk management function.

Most jurisdictions embarked on restructuring with the anticipation that electricity prices would decline over time, or at least not rise as much as in the regulated environment. The basic driving forces behind that anticipation were technology, which was expected to reduce generation costs, and competition, which was expected to improve efficiency.

Time-of-Use (TOU) Rates
As indicated above, a feature of competitive wholesale markets is that prices may fluctuate significantly, subject to market conditions and competitive forces. Further, because electricity cannot be easily stored prices can exhibit pronounced hourly swings.

Consumers can take advantage of these hourly swings by altering their consumption patterns. For example, industrial consumers can reschedule production into off-peak times. Conceptually, residential consumers could also reschedule activities, for example, away from the morning and evening peaks. In the traditional regulated market, utilities use moral suasion to perform that function, because there is usually no economic incentive.

A number of observers have pointed out that real-time price signals, i.e., higher prices during peak hours, would be necessary to induce consumers to reduce consumption.

Advantages and Disadvantages of Restructuring
By moving from a cost-of-service environment to the competitive environment implied by restructuring, there are a number of advantages and disadvantages.

Advantages include:

• increased competition, more customer choice, possible service improvements;
• potentially lower costs, if competition results in improved efficiency;
• marginal cost pricing better reflects market conditions and gives better price signals to market participants; and
• trade will tend to promote price convergence between regions: high-price regions could experience lower prices.

• price uncertainty due to changing market conditions;
• possible upward pressures on prices due to increased costs for some market participants (e.g., higher costs of capital because of higher risks);
• higher risks mean uncertainty for new investment compared with cost-of-service regulation;
• marginal cost pricing means more volatility, potential for price spikes;
• trade will tend to promote price convergence between regions: low-price regions could experience higher prices.