The road leading to competition in Alberta’s electricity industry has been a long and winding one with many obstacles along the way.
This article reviews the historical development of electricity restructuring, some of the key issues facing the industry today and speculation about future developments.
Prior to 1982, there were three major utility suppliers of electricity in Alberta — ATCO Electric, EPCOR and TransAlta Utilities. Consumers in each utility franchise area paid a different regulated rate for power.
Generally, consumers in southern Alberta paid a lower rate for electricity than consumers in the northern part of the province.
From a political and economic perspective, this was considered to be an inequitable situation for Albertans and, as a result, the Electric Energy Marketing Act was promulgated in 1982. EEMA reduced price disparities for consumers by averaging generation and transmissions costs on a provincewide basis.
Unfortunately, two unintended side effects of EEMA were to distort utility planning decisions and to reduce incentives for cost minimization.
In the early 1990s, the government of Alberta commenced a policy review and discussions with industry stakeholders on ways to develop solutions to the issues related to EEMA. This led to the Electric Utilities Act, 1995, which came into effect on Jan. 1, 1996.
Highlights of the EUA include:
* separation of generation, transmission and distribution functions;
* creation of a system of statutory payments and entitlements between generators and distributors called “legislated hedges,” whereby incumbent generators are required to sell their power at variable cost in exchange for payments covering their fixed costs; and
* creation of a non-profit Power Pool through which all electricity is traded and a regulated, and a for-profit Transmission Administrator which operates the provincial transmission system and administers transmission tariffs, including the costs associated with ancillary services and congestion management.
The EUA, 1995, focused primarily on structuring the wholesale market and did not deal with retail competition. The legislated hedges were created as a mechanism to ensure consumers in Alberta did not pay more than the “regulated price” for generating capacity owned by the incumbent utilities prior to January 1, 1996.
In addition, legislated hedges were to act as a transitional mechanism to mitigate the incumbent generators’ potential to exercise market power.
The failure to address a long-term plan to mitigate potential market power created uncertainty within the industry and inhibited the development of Alberta’s electricity market during its first two years of operation.
This led to passage of the Electric Utilities Amendment Act in 1998. The amendment remedied two shortfalls of the previous act. One, it provided for retail competition to be implemented by January 1, 2001, and two, it replaced the legislated hedges with Power Purchase Arrangements.
PPAs are auction biddable contracts that cover the embedded costs of existing generation. The PPAs were auctioned to interested parties in August 2000. The holder of a PPA is entitled to sell the output of the generating plants directly to consumers in exchange for paying the owner the actual cost of generating power over the remaining life of the facility or until 2020, whichever comes first.
PPAs representing approximately 4,350 MWs were sold at an auction in August 2000 to Enmax, EPCOR, Engage Energy, TransCanada and Enron. The bid premiums paid by the winning bidders, approximately $1.2 billion, have been returned to consumers in Alberta as part of the electricity rebates.
From the perspective of consumers, the objectives of restructuring are lower prices, choice of suppliers, reduced role of government (lower administrative costs) and increased economic efficiency (achieving the least costly method of generating electricity).
The challenge is to create what’s known as “workable competition.” While there is no generally accepted model for a competitive electricity market, there are a number of characteristics that economists do agree on. Some of the characteristics of a competitive market include:
* many buyers and sellers; * no one participant can manipulate prices or create barriers to entry; * bid/offer strategies of each participant are unknown to other participants (required to prevent gaming);
* market participants who are willing to assume risk (speculators) and participants who are risk averse (hedgers); and
* market participants who are able to respond to price signals, (i.e., when prices are high, developers build new generating capacity and/or consumers defer or reduce purchases).
From the commencement of restructuring in Alberta (January 1, 1996), average annual power pool prices have risen steadily from $14.42/MWh in 1996 to $133.22/MWh in 2000.
Since the beginning of the year, the wholesale price has declined to approximately $100/MWh during on-peak periods.
The price increase over the 1996 -2000 time period was due to a number of factors such as a tightening supply/demand balance, high natural gas prices and an increased reliance on imported power from BC Hydro/Powerex which tended to reflect the higher cost of power in the California market place.
While it is extremely difficult to accurately forecast electricity prices, industry analysts expect prices to remain high and range from $60/MWh to $100/MWh over the next two to three years.
The fundamental problem in the Alberta market is the lack of sufficient new generating capacity and, to a lesser extent, the inability of a broad base of consumers to respond to price signals.
A significant portion of the new generating capacity which has or is expected to come on-line over the next three to four years will be dedicated to industrial applications.
Growth in electricity demand will need to be met by the construction of merchant power plants (i.e. no specific, dedicated market). In order for new merchant power plants to be built, developers will require a strong, sustained price and relative certainty of rules and regulations, particularly in the environmental approval process for new capacity.
Ironically, in a restructured, competitive market, price spikes appear to be necessary to encourage new plant construction. In Alberta’s market design, there is no guarantee that generators will recover their capital investment. Thus, they have an incentive to bid up the market price, over and above fixed and variable generating costs, when the opportunity arises.
This bidding behaviour, in conjunction with a highly inelastic demand curve, can increase prices to as much as $1000/MWh, which is the maximum permissible price. This usually occurs during periods when supply is constrained such as during the coldest days of winter or when there has been an unexpected plant outage.
In addition to short-term price spikes, some industry analysts suggest that new plant construction will follow a ‘boom-bust’ cycle over the long-term, where prices will rise as supply/demand tightens (to the benefit of developers) and fall after new capacity comes on line (to the benefit of consumers).
The duration of the cycle is expected to last anywhere from three to 10 years depending on the availability of generating equipment, environmental issues and approval processes.
There are three important factors which will help to reduce the overall level of market prices in Alberta.
The first is an increase in generating capacity. The current supply/demand balance in the province is very tight. However, approximately 6,000 MWs of proposed new plant capacity is scheduled to come on-stream over the next five years. Not all of this capacity will actually be built, but it is expected a substantial portion will result.
The second factor relates to the role of the Clover Bar gas-fired generating plant as one of the key price-setting units in the Alberta market. It tends to be a higher-cost unit and industry stakeholders are evaluating possible mechanisms to mitigate the influence of the plant on wholesale market prices.
The last factor concerns improving demand-side response. This could be accomplished by introducing a competitive market for meter services and by converting cumulative hour meters to interval or real-time meters that would be used to measure electricity consumption.
The benefit of converting to interval and real-time meters is that it would allow consumers to respond directly to price signals by curtailing or deferring energy consumption. This would have the benefit of reducing hourly demand which in turn would result in a lowering of the market price for electricity.
In addition, converting to interval and real-time meters would encourage retail competition by facilitating the development of different products and services, particularly for managing risk associated with volatile prices.
The development of competitive wholesale and retail markets is a long-term process. There are many complex issues, and it has not always been easy to achieve consensus among industry stakeholders.
In short, competitive electricity markets cannot be created; they must be given a chance to evolve. Only then will Albertans be rewarded with the benefits of competitive markets — lower prices and customer choice.
Rob Spragins is director, Electricity Research for the Canadian Energy Research Institute. CERI is a non-profit energy and environmental research organization located in Calgary. Members of CERI include provincial and federal governments, energy producers, service providers and consumers.
