Reprinted with Permission from the 2006 issue of the Lexpert/ALM Guide to the Leading 500 Lawyers in Canada. (c) Thomson Carswell."
The approach to 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 played a key role in Alberta’s decision 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. However, in most instances provincial energy policies have sought to encourage competition and private-sector development of new generation facilities. The following sections summarize the recent opportunities for private-sector investment and the corporate/commercial activity in the electricity markets of the four largest populated regions in Canada.
In 2005, the Province of Ontario further developed its most recent policy shift towards "hybrid" electricity markets. The hybrid concept is based on a compromise approach of combining seemingly divergent policies. One basic tenet is the regulation by the Ontario Energy Board (OEB) of the prices payable for energy produced by baseload hydro and nuclear generation assets of the provincially owned generation company, Ontario Power Generation. As other generators’ power prices remain unregulated, market prices are a blend of OEB-approved and market-set rates. A second basic tenet is the encouragement of private investors to develop projects that rely on publicly funded long-term power procurement agreements. The duality of Ontario’s approach to attracting investment has been made necessary by the failed attempt to implement fully competitive wholesale and retail markets in May 2002, and by the flight of private capital from Ontario that resulted from the volatility of Ontario’s subsequent legislative policy shifts in the wake of the failure.
Over the past year, as part of Ontario’s gradual move back towards competitive retail markets, another major step was taken in weaning the province’s electricity consumers from artificially low electricity prices. Under the newly implemented Regulated Price Plan, the OEB looks at the forecasted costs of generation over the following year to set the electricity prices charged to consumers. Although at the moment a gap remains between the prices paid by consumers and the actual costs of generation, the OEB will keep track of the difference and make up the shortfall in future electricity rates. The ultimate goal of the plan is to ensure that future rates reflect the true cost of power. The current rate has been set at $0.05 for the first 750 kWh of consumption and $0.058/kWh thereafter (with adjustments to the rates depending on the consumer and the season).
Further development also continues in the wholesale markets. In an effort to develop a robust energy-forward market, promote greater liquidity and help predict future prices in the wholesale markets, the Ontario Power Authority (OPA) introduced a two stage auction for at least 500 MW of firm, multi-year power contracts to be sold in 25MW and 5MW lots. The first stage of the auction resulted in sales of approximately 5.79 TWh of power at an average price of $73.51 per MWh. The second stage will be conducted in April 2006.
In addition to facilitating the wholesale energy auction, the fledgling OPA commanded significant attention in 2005 for other reasons. The OPA was established in 2005 with a mandate to, among other things, manage and ensure the stability of long-term energy supply within the province. In December 2005, the OPA published its long-awaited "Supply Mix Advice Report." Not surprisingly, the report predicted a shortfall in provincial generation capacity of approximately 24,000 MW by 2025 due to increasing demand and the provincial government’s earlier commitment to phase out coal-fired generation prior to 2010. To fill this gap, the OPA recommended the construction of significant new generation capacity. A substantial amount of such capacity is to come from renewable energy sources.
The OPA also recommended replacing coal with gasfired generation and, more controversially, maintaining or replacing nuclear capacity, which currently comprises 37 per cent of Ontario’s supply portfolio. The report also envisioned that savings of approximately 1,800 to 4,300 MW could be achieved through conservation and demand management efforts.
As reported in Lexpert last year, efforts to construct new generation are already underway, mostly in response to requests for proposals (RFPs) issued by the OPA or projects initiated by the province and assumed by the OPA. These projects comprise approximately 9,520 MW of new generation, including renewable energy supply, natural gas-fired generation, demand-side management and 1,500 MW of nuclear energy from the refurbishment and restart of two units at the Bruce A Nuclear facility.
The OPA’s procurement initiatives in 2005 entailed several RFPs for new generation and conservation, in which the OPA offered 20-year power purchase agreements or contracts for differences to successful bidders. Two RFPs totalling 1,200 MW of renewable energy supply were released in the spring and summer of 2005. At the start of 2006, the OPA issued an RFP for an aggregate of 1,000 MW from combined heat and power and district energy projects. In the near future, the OPA will issue another RFP for 1,000 MW of generation to be built west of Toronto, plus an additional 600 MW in downtown Toronto. On the conservation side, the OPA also sought proposals for 20 MW of demand response projects in the northern York Region, and 250 MW of demand response and demand side management projects across the province. Other significant procurement initiatives include negotiations by the OPA for the purchase of electricity from the 900 MW gas-fired Goreway Station to be constructed by Enbridge and Sithe. The province has also contracted to purchase 1,500 to 3,000 MW of hydro power from Manitoba beginning in 2006 at 150 MW. Annual increases are anticipated thereafter, dependent upon the construction of new inter-provincial transmission capacity to service such supply.
All of the OPA’s RFPs have been oversubscribed, suggesting that initial discomfort of investors, lenders and developers with the creditworthiness of the OPA has subsided. However the OPA’s processes have not been completely trouble-free. One project representing 280 MW of new gas-fired generation was quietly cancelled in August, and the insolvency of certain U.S. and Canadian affiliates of another successful co-developer has raised concerns about the viability of a 1005 MW project.
The strength of the income trust markets and the high number of generation projects in Ontario financed through them wavered in 2005. This drop in activity resulted from the income trust market being thrown into uncertainty when the federal government announced it would review the favorable tax treatment that has spurred such investment vehicles’ popularity. In late November, it was announced that the tax treatment of income trusts would not be changed. It is expected that the combination of demand for new generation and the restabilization of the income trust market will offer developers and investors continued opportunities in Ontario in the short to mid term.
In Quebec, Hydro-Québec’s operations are functionally separated into a generation division (HQ Production), a transmission division (TransÉnergie) and a retail distribution division (HQ Distribution). 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 and Natural 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 longterm fixed price supply contract between HQ Production and HQ Distribution, under which the bulk of Hydro-Québec’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 cent per year until 2008, and Hydro-Québec 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 privatesector 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’s Magpie project, Innergex’s Matawin project and Regional Power’s Angliers project, each of which is currently under development. Very few new projects have arisen in the small hydro sector in Québec, and the market has been consolidated through income funds such as Boralex, Innergex, Great Lakes and Algonquin Power.
HQ Distribution proceeded with an initial call for tenders for 600 MW of capacity in February 2002, which was subsequently increased to 1200 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. 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 1000 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. (739.5 MW) and two bids from Northland Power Inc. (250.5 MW) for a total of 990 MW. Located in the Gaspésie Peninsula, the projects will represent an overall investment of $1.9 billion and will increase Quebec’s installed wind power capacity to over 1100 MW. This compares to Canada’s current installed wind power capacity of 682 MW, including 113.25 MW of capacity already in place in Quebec.
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, which was expected to follow, has not yet been launched. Furthermore, 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 and Natural Resources recently tabled a new energy policy paper. It was anticipated that a parliamentary commission would be established to review the policy paper and the different sources of potential generation in Quebec, including hydroelectric, cogeneration, gas-fired, wind and solar. Shortly after such policy was tabled, in late 2004, HQ Production’s 800 MW gas-fired Le Suroît project was cancelled.
On October 31, 2005, HQ Distribution issued a call for tenders for 2000 MW of wind-generated electricity. The deadline for submitting bids is April 17, 2007. Pursuant to such call, HQ Distribution intends to purchase 2,000 MW of capacity generated by wind farms in Quebec. The requirements will be distributed as follows:
- 300 MW starting on December 1, 2009
- 400 MW starting on December 1, 2010
- 400 MW starting on December 1, 2011
- 450 MW starting on December 1, 2012
- 450 MW starting on December 1, 2013
A bid may apply to all or a portion of an annual requested quantity. The terms of the contracts may range from 15 to 25 years. In addition to the previous bidders, it appears from the pre-bid conference’s attendance that several large U.S. and European players are interested in participating in this new call for tenders.
Over the past five years, annual peak demand on the Alberta Interconnected Electric System (AIES) grew at an average rate of 1.4 per cent and annual energy consumption grew by 1.2 per cent. In response to these trends, between 1998 and 2005, Alberta’s electricity market attracted more than 3,800 MW of new private-sector generation, representing more than $2 billion in new investment. As of December 31, 2004, Alberta had approximately 12,000 MW of generation available to the AIES. Nevertheless, according to the Alberta Electric System Operator’s (AESO) "20-Year Outlook Document (2005–2024)" (20-Year Outlook), published in June 2005, an additional 6,150 to 13,400 MW of new generation must be integrated into the AIES over the next 20 years to satisfy the forecasted 2 per cent annual average growth in both peak demand and energy consumption.
Alberta’s existing electric generation resources are mainly comprised of hydro, coal, gas and wind. In addition, Alberta has significant undeveloped coal reserves and cogeneration opportunities. A significant part of the province’s generation facilities are located in northern and central Alberta. Industrial and residential loads, on the other hand, tend to be situated in the central and southern regions. Transmission, therefore, plays a key role in attaining and maintaining the efficient operation of the AIES. This fact was acknowledged in 2005 by the Alberta Department of Energy (Alberta Energy) in "Alberta’s Electricity Policy Framework" (the policy), which concluded that supporting a market structure requires transmission to be available to all supply and load customers with sufficient capacity to ensure that neither load nor generation is constrained. Central to the policy, as implemented by the Transmission Regulation, A.R. 174/2004, is the principle that establishing adequate transmission is the agent of reliability and the facilitator of a competitive market.
Despite this recognition of the transmission system’s importance to the AIES, many parts of Alberta’s transmission grid are reaching or exceeding the grid’s capability to reliably serve growing load and to integrate new generation. Under the policy, the AESO has been tasked with proactively identifying, planning and implementing transmission system reinforcements, so that facilities are in place to ensure reliable and economic system operation, facilitate competitive electricity markets, minimize the reliance on must-run generation and enhance/restore import and export capabilities.
To help accomplish its tasks under the policy, the AESO applied for and received approval from the Alberta Energy and Utilities Board (AEUB) in 2005 to implement two projects that will reinforce the transmission system: the first with respect to the North-South corridor, and the second with respect to the southwest transmission system.
The North-South project includes the construction of a new 330-kilometre 500 kV line from the Genesee generating station west of Edmonton to the Langdon substation east of Calgary. The line is estimated to be in service in September 2009. The AEUB is now working with the AltaLink and EPCOR, two of the province’s transmission facility operators (TFOs), to develop detailed specifications and cost estimates for them to submit their facility applications to the AEUB. It is currently anticipated that such filings will be made in June 2006. In addition, the project calls for the conversion of select existing substations and transmission lines located southwest of Edmonton from 240 kV to 500 kV. The anticipated in-service date for these upgrades is October 2007. Both AltaLink and EPCOR have provided proposals for service and estimates for their respective portions of this conversion project. According to the AESO, the anticipated benefits of this North-South Project, which carries a forecast price tag of $339 million, include improved capacity to reliably serve Alberta (Red Deer and south), removal of barriers to new generation and significant line-loss savings.
The southwest project consists of transmission additions and upgrades required to maintain reliability of supply to loads in the Pincher Creek area and certain proposed generating plants, predominantly wind farms, that are in the advanced stages of the interconnection application process. The project has a forecast in-service date of February 2007 with a forecast cost of $92 million. The AEUB is now working with AltaLink to develop detailed specifications and cost estimates for AltaLink to submit its facility application to the AEUB. This project is viewed by wind developers as long overdue and critical for continued development in southwestern Alberta. The Pincher Creek area has seen approximately 330 MW of generating capacity installed recently (including TransAlta’s Summerview Wind Farm, which opened in May 2005), and an additional 600 to 800 MW of new wind generation is anticipated by the end of 2006. In December 2005, Creststreet Power & Income Fund LP announced its commitment to fund up to $31 million in Kettles Hill Wind Energy Inc., whose 63 MW wind power project is being developed near Pincher Creek, comprised of 35 1.8 MW turbines adjacent to a 138 kV transmission line.
Based on the 20-Year Outlook, a number of significant additional transmission expansion projects are likely in the foreseeable future including: (a) 500 kV line reinforcement from the Fort McMurray area; (b) further reinforcement of the Edmonton-Calgary transmission system, including a second 500 kV line; and (c) additional 240 kV developments in Grande Prairie, East Edmonton-Fort Saskatchewan, Lloydminster, Calgary, Lethbridge-Medicine Hat and Pincher Creek.
Also given consideration in the 20-Year Outlook is the importance of transmission interties between Alberta and other jurisdictions as a means of ensuring overall reliable supply of service. According to the policy, transmission interconnections with neighbouring jurisdictions are essential to a well-functioning power market as they support reliability, price stability, generation development and continued economic growth. In compliance with the policy and the Transmission Regulation, the AESO is working to restore existing interties to original design ratings and facilitating the development of merchant intertie projects with Saskatchewan, British Columbia and the Pacific Northwest (including TransCanada’s NorthernLights initiative and the Montana-Alberta Tie interconnection).
On the M&A front, TransCanada Corporation sold its interest in TransCanada Power, LP (now EPCOR Power LP), owner of numerous power plants throughout North America, to EPCOR Utilities for $529 million in September 2005. EPCOR’s acquisition included approximately 31 per cent of the outstanding units in TransCanada Power, 100 per cent of the general partner in TransCanada Power, and management and operations agreements governing the ongoing operation of TransCanada Power’s generation assets.
In 2005, TransCanada Corporation acquired the remaining rights and obligations of the 756 MW Sheerness Power Purchase Arrangement from the Alberta Balancing Pool for $585 million. The remaining term of this PPA is approximately 15 years and the acquisition closed on December 30, 2005. The Sheerness Power Plant is located approximately 230 kilometres northeast of Calgary and is comprised of two 390 MW coal-fired thermal power generating units. It is co-owned by a subsidiary of ATCO, which also operates the plant, and TransAlta Cogeneration LP.
AltaLink and its owners are currently before the AEUB seeking approval to effect a change in ownership that would see the Ontario Teachers’ Pension Plan Board and Trans-Elect, Inc. divest themselves of their ownership interests in the TFO, which interests are proposed to be picked up indirectly by the other two existing owners, SNC-Lavalin Group and Macquarie Essential Assets Partnership. Under the proposed new corporate structure, which was announced in November 2005, SNC-Lavalin Group would indirectly own approximately 77 per cent of AltaLink and Macquarie would indirectly own approximately 23 per cent of AltaLink.
The investment climate for independent power producers in British Columbia has improved significantly under the 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 development by Independent Power Producers (IPP). While public ownership of BC Hydro’s generation, transmission and distribution assets continues, BC Hydro has been reorganized into separate generation and distribution divisions. In addition, a new Crown corporation, British Columbia Transmission Corporation (BCTC), has been created to independently plan, manage, operate and provide nondiscriminatory access to BC Hydro’s transmission system. In June 2005, the British Columbia Utilities Commission (BCUC) approved an application by BCTC for an Open Access Transmission Tariff that is in line with British Columbia’s "open access" market design.
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 industrial and large commercial customers, and in 2005 the BCUC approved 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-river hydro projects. A total of 21 of more than 100 submitted projects were accepted by BC Hydro under its 2002/03 "green" power generation call and its 2002 customer-based generation call. On a combined basis, the 21 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).
As a result of a decision by the BCUC in 2003 to deny BC Hydro’s application to build a proposed 265 MW gasfired generation plant at Duke Point on Vancouver Island, BC Hydro issued a call for tenders for power projects on Vancouver Island. A bid by Duke Point Power Limited Partnership (DPPLP) for a plant similar to BC Hydro’s proposal was selected as the successful bid, and in early 2005 an EPA between BC Hydro and DPPLP was accepted for filing by the BCUC following a contested public hearing. Several intervenor groups were granted leave to appeal the decision of the BCUC to accept the EPA, and BC Hydro subsequently announced its decision to terminate the EPA. In an effort to meet the projected capacity shortfall on Vancouver Island left by the loss of the Duke Point project, BCTC and a private developer, Sea Breeze Pacific Regional Transmission System Inc., have each filed applications with the BCUC for approval of proposed projects for the transmission of electricity from the mainland to Vancouver Island. A joint public hearing for both applications is being held in early 2006 by the BCUC, and the BCUC’s ruling on the applications is expected in the spring.
In December 2005, BC Hydro issued a F2006 open call for power. Under the open call, BC Hydro is seeking to procure approximately 2,700 GWh per year of firm electrical energy from IPP projects with commercial operation dates on or before November 2010. Approximately 200 GWh per year of this power commitment is to be generated by smaller projects with capacities between 0.05 and 10 MW. Tenders are to be submitted by bidders in April, and successful bidders will be announced in August. Energy from successful projects is to be delivered to BC Hydro under 15 to 40 year EPAs.
In fall 2004, the Columbia Basin Trust announced its intention to sell its interest in three hydroelectric projects and one development project in the Columbia River Basin to BC Hydro. Although this transaction was not completed because of public opposition, BC Hydro has invited the submission of an offer in respect of the purchase of additional electricity from one of the projects (the Brilliant Expansion Project). This invitation is separate from the 2006 open call and will not materially alter the procurement targets in the call.
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