Skip to main content

Restructuring Canadian Electricity Markets

The approach toward restructuring electricity markets has differed across Canada as a result of the unique industry and regulatory structures, regional circumstances and issues that face each of the provinces. For example, factors such as anticipated rapid growth in energy consumption and the need to replace aging power generation infrastructure were key in the decision by Alberta to pursue restructuring of its electricity industry in 1996. Ontario, by contrast, decided to pursue restructuring of its electricity industry to address, among other things, serious concerns regarding the fiscal and operational performance of Ontario Hydro. This regional diversity, together with different governmental responses, has resulted in unique regulatory regimes in each of the provinces. In most instances, however, provincial energy policies have sought to encourage competition and private sector development of new generation facilities. The following summarizes the recent opportunities for private sector investment and the corporate/commercial activity in the electricity markets of the four most populated regions in Canada.


The mood in the Ontario electricity industry can be described as "cautiously optimistic." Industry participants have learned to be cautious since deregulation began in 1998. Two keystone elements of deregulation were the restructuring of government-owned electricity monopolies and the introduction of full competition to electricity markets. These elements suffered significant setbacks in the last two years, including:

  • cancellation of the province's attempt to find an investor in the provincial transmission company following its aborted IPO;
  • discontinuance of Ontario Power Generation Inc.'s ("OPG") divestiture program that had the objective of stimulating supply competition; and
  • effective closure of retail markets through the re-regulation of electricity prices for low-volume consumers.

Adding to recent sector destabilization are significant concerns about electricity supply adequacy. A provincial task force reported in January 2004 that due in part to the government's commitment to shut down its coal-fired generation stations, if substantial capacity or conservation measures were not taken the province might not have sufficient generation to meet its peak requirements by 2006.

New generation has been built in Ontario since 1998, but increases in capacity have been modest. A 581 MW combined cycle plant owned by OPG and ATCO Gas was commissioned in July 2004, and a 440 MW cogeneration plant was commissioned by TransAlta in March 2003. "New" capacity also includes the return to service of nuclear generating units A3 and A4 by Bruce Power L.P. (1,500 MW) and the troubled return to service of Pickering A4 (515 MW) by OPG.

Since deregulation has not yet produced the signals for necessary investment, the provincial government has made itself a catalyst by offering long-term power procurement agreements and thus creating optimism in the area of energy project development. On June 24, 2004, the province issued an RFP soliciting 300 MW of "renewable" capacity and on September 20, 2004, issued another RFP soliciting 2,500 MW of "clean" capacity and demand-side management projects. Both RFPs garnered significant interest from developers as reflected by submissions of final proposals representing 1,100 MW of renewable capacity and over 8,200 MW of clean generation and conservation projects. The province rewarded this enthusiasm in November when it announced it had over-allotted ten renewable projects totalling 395 MW and would be issuing a new RFP for renewable capacity as early as January 2005. The winning clean energy projects will be announced in February 2005 and it is widely believed that another clean energy RFP will also be announced shortly thereafter.

The strong response to the RFPs has been gratifying in light of Ontario 's investment climate and industry concerns regarding the RFPs. Initial comments on the 20-year contracts raised questions about their financability. One particular concern is the creditworthiness of the proposed buyer. Currently, the Ontario Electricity Financial Corporation, a Crown agent, is the proposed buyer. However, the agreements may be assigned to an unknown entity, the Ontario Power Authority ("OPA"). The OPA will be a not-for-profit corporation to be created pursuant to Bill 100, which was introduced on June 15, 2004. Based on several factors, including the understanding that it will be legislatively entitled to recover its costs from electricity consumers, the OPA has received provisional ratings of Aa3 from Moody's and A (high) from the Dominion Bond Rating Service. Both rating services' reports highlight factors and assumptions (including implicit recognition of the unpredictable policy shifts in Ontario 's restructuring experience) that could materially affect these ratings. The financability of the agreements will likely only be seen once successful bidders to the RFPs are announced.

Several other significant projects have been announced since June 2004 and are dependent upon participation by the province:

  • the upgrade of the Sir Adam Beck Generating Station to produce an additional 1.6 TWh of electricity annually;
  • the refurbishment and restart of an OPG 515 MW nuclear generating unit;
  • the potential refurbishment and restart of two 770 MW nuclear generating units by Bruce Power; and
  • the development of up to 1,500 MW of hydroelectric cap-acity in Manitoba and an interconnection line to Ontario.

In the area of corporate finance, although the popularity of income trusts waned in early 2004, low interest rates maintained the activity of generation-backed trusts. Canadian income trusts continued to refine their structures in 2004, particularly to respond to concerns raised by auditors regarding cross-border interest deductibility issues. Innovative structures, such as flow-throughs of preferential tax treatment for renewable generation, were created. Also, several established income funds went back to the markets to raise debt for the purposes of expansion or refinancing existing credit facilities.

Some of the indicative income fund IPOs in the last year included Creststreet Power & Income Fund L.P. ($42 million flow-through share offering for the construction of 12.6 MW of test wind turbines in Quebec and Nova Scotia), Macquarie Power Income Fund ($212 million for the acquisition of a 156 MW cogeneration plant) and Countryside Power Income Fund ($149 million for Canadian district energy systems and U.S. landfill gas projects).

Other than acquisitions by income funds, M&A activity in Ontario has continued to be sluggish. The hoped-for consolidations among local distribution companies have still failed to materialize due to, among other things, uncertainty as to rates of return that will be permitted on distribution assets. One future area of promise is the expected divestiture by OPG of its non-core businesses (e.g., renewable generation) following the report of the OPG review committee chaired by the Honourable John Manley which recommended that OPG concentrate on ownership of its major facilities.


In Quebec, Hydro-Quebec's operations are functionally separated into a generation division ("HQ Production"), a transmission division ("TransÉnergie") and a retail distribution division ("HQ Distribution"), where each division operates as a separate and distinct entity. HQ Production is not a regulated entity and reports directly to the Quebec government through the Minister of Energy, Mines and Resources. TransÉnergie and HQ Distribution are regulated by the Régie de l'Énergie and, subject to minor exceptions, are the exclusive transmitters and distributors of electricity throughout Quebec.

Although HQ Production is not regulated by the Régie, in 2000 the Quebec government mitigated HQ Production's market power in the generation sector by legislating a long-term fixed-price supply contract between HQ Production and HQ Distribution under which the bulk of Hydro-Quebec's current generation portfolio was committed to the Quebec distribution market at a fixed price. HQ Production is required to provide HQ Distribution with up to 165 TWh of electricity per year at a price of 2.79¢ per kWh. Additional supply for the Quebec market must be obtained by HQ Distribution through competitive bidding. HQ Production is allowed to bid for new capacity within this process, subject to conflict of interest and code of ethics provisions.

Electricity demand in Quebec is expected to rise by about 1.3% per year until 2008, and Hydro-Quebec has been under pressure to develop new sources of supply. Several calls for tenders have been issued, and new calls are expected, resulting in a number of opportunities for private sector developers.

In late 2002, HQ Production issued a call for tenders for small hydro facilities. While the call initially listed 36 potential sites in the province, in the end only a handful of sites with existing dams to be refurbished were selected. Those sites include Hydroméga Inc.'s Magpie project, Innergex Inc.'s Matawin project and Regional Power Inc.'s Angliers project, each of which is currently under development. There are very few new projects in the small hydro sector in Quebec, and there has been a consolidation of the market by income funds such as Boralex Inc., Innergex, Great Lakes Power Ltd. and Algonquin Power Income Fund.

HQ Distribution proceeded with an initial call for tenders for 600 MW of capacity in February 2002, which was subsequently increased to 1,200 MW. Under this call, a 600 MW gas-fired project proposed by Calpine and Axor was selected, as were two HQ Production projects totalling 600 MW. Calpine and Axor subsequently decided not to proceed with their project and, as a result, TransCanada Energy's 507 MW Bécancour gas-fired generation project was selected as the next runner-up in the bid process. The HQ Production and TransCanada projects are expected to be in service by the end of 2006.

In April 2003, HQ Distribution issued a call for tenders for 100 MW of biomass generation capacity for which it received bids totalling 71 MW. HQ Distribution has selected three bidders, and two have signed power purchase agreements.

In May 2003, HQ Distribution issued a call for tenders for 1,000 MW of wind-generated electricity to be delivered between 2006 and 2012. On October 4, 2004, HQ Distribution announced it had selected six bids from Cartier Wind Energy Inc. and two bids from Northland Power Inc., for a total of 990 MW. The projects will be located in the Gaspé Peninsula, will represent an overall investment of $1.9 billion and will increase Quebec 's installed wind power capacity to over 1,100 MW. This compares to Canada 's current installed wind power capacity of 372 MW, including 113.25 MW of capacity already in place in Quebec. HQ Distribution is expected to announce shortly another 1,000 MW wind power call.

On October 6, 2004, HQ Distribution issued a call for tenders for 350 MW of cogeneration capacity for deliveries commencing December 1, 2009, at the latest. A second call for tenders for up to a further 450 MW of new cogeneration capacity is expected to follow, subject to market requirements. Also on October 6, 2004, HQ Distribution issued a short-term call for tenders to meet electricity requirements in Quebec for 2005.

The Minister of Energy is expected to table a new energy policy paper in the near future. It is anticipated that a parliamentary commission will be established to review the policy paper and the different sources of potential generation in Quebec, including hydroelectric, cogeneration, gas-fired, wind and solar. HQ Production's controversial 800 MW gas-fired Le Suroît project was cancelled by the government in November, 2004.

On the corporate finance and M&A front in Quebec, Innergex Power Income Fund went public in July 2003, with eight hydroelectric facilities with a total installed capacity of 70.5 MW. Also in 2003, Boralex Power Income Fund acquired 100% ownership interest in two hydroelectric power stations in New York State and with these acquisitions, the fund's total installed capacity increased from 131.0 MW to 191.0 MW. Earlier in 2004, Kruger formed an energy division and recently acquired two hydroelectric facilities in the United States.


Between 1999 and 2003, Alberta 's electricity market attracted 3,000 MW of new private sector generation, representing approximately 40% of the total new generation installed in Canada during this period, with an additional 5,200 MW of new generation proposed or under construction. Although this growth in generation has resulted in a surplus of generation capacity in Alberta, the challenge is to ensure that the electricity market continues to attract investment in the long term, particularly in light of growing demands for investment in other provinces.

One of the key challenges facing Alberta relates to the province's transmission system. The transmission grid in many parts of Alberta is reaching or exceeding its capability to reliably serve growing load and to integrate new generation. The Alberta Electric System Operator ("AESO") has indicated that without significant upgrades to the north-south transmission corridor, the system will face reliability concerns and will become a major impediment to northern generation development beyond 2005, including generation development in the Lake Wabamun area and future oil sands-associated cogeneration plants in the Fort McMurray area. In addition, in the south-western area of the province, which has the highest wind energy potential in Alberta, the existing transmission system does not have sufficient capacity to interconnect new generation and has become a barrier to generation development in the area.

In December 2003, the Alberta Department of Energy issued a transmission development policy paper that establishes the principles governing electricity system planning and development in the province. The key feature of the policy is the adoption of the principle that adequate transmission must be in place to support generation development. Under the policy, load customers will become responsible for the embedded costs of transmission service, while generators will be responsible only for their local interconnection costs and location-based loss charges, as well as yet-to-be-determined payments toward transmission system upgrades.

In August 2004, the new Alberta transmission regulation, AR 174/2004, came into force implementing the new transmission policy. Among other things, the regulation includes the requirement for the AESO to achieve a transmission system that is sufficiently robust to allow for the transmission of 100% of in-merit energy under normal conditions and the transmission on an annual basis of at least 95% of in-merit energy under abnormal conditions.

In response to the transmission policy, the AESO made two applications to the Alberta Energy and Utilities Board to reinforce the transmission system, the first with respect to the north-south corridor between Edmonton and Calgary and the second with respect to the Pincher Creek-Lethbridge area transmission system in the southwest. The north-south proposal includes a new 330-kilometer 500 kV line from Edmonton to Calgary as well as the conversion of certain existing lines from 240 kV to 500 kV. The anticipated in-service date for the upgrades is 2009.

The southwest proposal consists of transmission additions and upgrades required to serve existing generation in the area and certain proposed generating plants, predominately wind farms, that are in the advanced stages of the interconnection application process. The proposal is viewed by wind developers as long overdue and critical for continued development in the area. The Pincher Creek area has seen 220 MW of generating capacity installed to date and is expecting a further 600 MW of new wind generation to be developed by the end of 2005.

In November 2004, after consultation with wind developers, the AESO finalized new wind power interconnection standards. The AESO will not apply the new standards to wind farm developments currently under construction or approved by the AESO for interconnection to the grid. Any new wind power interconnection application will be subject to the new standards. The new standards include matters such as voltage regulation requirements and "low voltage ride-through" capability to ensure that wind turbines can remain online through most common power disturbances.

In addition to the wind power interconnection standards, in January 2004, the AESO initiated a process to develop new interconnection process guidelines and standards. The purpose of the redesign of the interconnection process is to improve application times and to increase customer satisfaction. The target implementation date is March 31, 2005.

On the M&A front, Fortis Inc. completed the purchase of Aquila 's Western Canadian electricity assets on May 31, 2004 for aggregate consideration of approximately $1.48 billion. In Alberta, Fortis acquired 100,000 kilometres of distribution lines serving 385,000 customers in southern and central Alberta. In addition, Direct Energy Marketing Inc., a subsidiary of Centrica plc, completed its acquisition of ATCO's regulated retail energy business in Alberta in May 2004. The transaction was originally announced in 2002 and closed after lengthy negotiations and regulatory hearings.

British Columbia

The investment climate for independent power producers ("IPPs") in British Columbia has improved significantly under the new energy plan introduced by the provincial government in November 2002. One of the four cornerstones of the energy plan is "more private sector opportunities," and the plan includes a number of initiatives designed to encourage IPP development. While public ownership of BC Hydro's generation, transmission and distribution assets continues, BC Hydro has been reorganized into separate generation and distribution divisions, and a new Crown corporation, British Columbia Transmission Corporation ("BCTC"), has been created to independently plan, manage and operate and provide non-discriminatory access to BC Hydro's transmission system. British Columbia has an "open access" market design, and BCTC has filed an application with the British Columbia Utilities Commission ("BCUC") for a new open access transmission tariff to replace BC Hydro's existing tariff. Like the existing wholesale transmission tariff, the new open access tariff is based on the Federal Energy Regulatory Commission's Order 888 pro forma tariff (the norm in the Pacific Northwest ).

Under the energy plan, new generation of electricity is to be built by private developers and, except for possible involvement in major projects with cabinet approval, BC Hydro is limited to undertaking efficiency improvements at its existing facilities. BC Hydro's generation division supplies electricity from its existing generating stations to the distribution division at embedded cost under a "heritage contract" between the two divisions. The distribution division is required to acquire new sources of power on a least-cost basis from sources that include IPPs, customer-owned generation, imports, conservation efforts and efficiency improvements at existing BC Hydro facilities. IPPs are also now permitted to sell electricity to large industrial customers, and BC Hydro will be seeking approval in 2005 of a new "stepped" rate to encourage these customers to conserve electricity and obtain some of their electricity from suppliers other than BC Hydro.

There are numerous IPP projects in British Columbia at various stages of development, including many projects at the conceptual stage. Many of the projects are relatively small run-of-the-river hydro projects. In 2003, BC Hydro announced that a total of 21 projects successfully bid into its 2002-2003 green power generation call and its 2002 customer-based generation call. As an indication of the high level of industry interest, BC Hydro initially received over 100 proposals in response to the two calls. On a combined basis, the successful projects represent 560 MW of capacity and 2,260 GWh per year of new generation to be purchased by BC Hydro under 10 to 20 year electricity purchase agreements ("EPAs"). The projects must achieve commercial operation no later than September 30, 2006.

In October 2004, BC Hydro announced its intention to issue an open call to the private sector in the Spring of 2005 to acquire up to 1,000 GWh of electricity and to issue a second call in the Fall of 2006 for an additional 1,000 GWh of electricity. This announcement follows indications from BC Hydro that it now requires more electricity to be available earlier than was previously forecast. BC Hydro's actual future requirements, and the opportunities for IPPs, will depend on a number of factors, including the level of economic growth in the province, BC Hydro's planning criteria, the future of BC Hydro's natural gas-fired Burrard Thermal-generating station and the number of IPP projects that have signed EPAs with BC Hydro that actually achieve commercial operation.

BC Hydro announced in November 2004 that the proposed 252 MW gas-fired Duke Point Power project (owned by Macquarie Essential Assets Patnership, Pristine Power Inc. and private investors) was the successful bidder in BC Hydro's call-for-tenders process that began in 2003 for new capacity on Vancouver Island. The proposed facility is to be located at Duke Point near Nanaimo. The Vancouver Island call was the result of a decision by the BCUC in 2003 to deny BC Hydro's application to build a 265 MW gas-fired generation plant at the same Duke Point location. The BCUC found that BC Hydro had not demonstrated that its proposal was the least-cost alternative and that BC Hydro should issue a request for proposals for new generation on Vancouver Island to determine whether IPPs could provide more cost-effective alternatives. The EPA entered by BC Hydro for the Duke Point Power project requires BCUC approval and the BCUC will be conducting a public hearing in January 2005 to consider whether to approve the agreement.

In 2004, the BCUC approved Fortis Inc.'s acquisition of Aquila (B.C.) from Missouri-based Aquila without public controversy, unlike the situation when Aquila acquired Aquila (B.C.) (then called West Kootenay Power and Light Co.) in 1987. In November 2004, Columbia Basin Trust and BC Hydro announced that they would not be proceeding with a previously announced proposal under which BC Hydro would acquire three hydroelectric facilities and one project in development in the Columbia River basin from CBT Energy Inc. (owned by Columbia Basin Trust) and Columbia Power Corp., a Crown corporation. Two of the three facilities are operating (Brilliant and Arrow Lakes ); one is under construction (Brilliant Expansion); and the fourth is the proposed Waneta Expansion. CBT Energy and Columbia Power each own a 50% interest in the projects.


Was this helpful?

Thank you. Your response has been sent.

Copied to clipboard