Tough plant-retirement decisions being made in Canada to reduce its carbon footprint contrasts with America’s embrace of coal-based generation.
There is a certain irony in Ontario’s decision to phase out its coal-fired generation at a time when the demand for new coal-fired plants is growing in the rest of North America. Global Energy’s analysis of demand for coal for power generation suggests that growth in demand for coal is likely to continue and even challenge coal producers to step up their productive capacity and deliverability to meet that demand.
Today there are more than 37,000 MW of new coal plants planned to be operational before 2010, with more than 15,000 MW of clean coal technology (see Figure 2). Canada’s decision to turn its back on coal seems at odds with the rest of North America’s aspirations for a resurgent coal future restoring some diversity in the fuel mix, in which even higher sulfur content coal from places like the Illinois Basin are expected to strengthen as technology makes use of closer, cheaper, dirtier coal sources to produce a cleaner coal result.
As one of the 130 participants of the Kyoto Protocol, Canada faces a tremendous challenge. The country has pledged under Kyoto to cut its global-warming emissions to 6 percent below the 1990 level by 2012. But its emissions actually have been rising, at an average rate of 1.5 percent a year. A large part of this is the result of stronger than expected economic growth and the growing reliance of other countries on Canada’s energy exports. Extracting and transporting “oil sands” from Alberta in particular is highly energy intensive and a source of carbon dioxide.
Ontario’s power sector provides an example of how a changing regulatory environment and growing consumption of electricity can create serious supply problems. In a recently released report, the Ontario Power Authority (OPA) concluded that Ontario’s electricity sector might be facing the most challenging times in its history with current installed capacity below levels of 12 years earlier.1 Total capacity needs by 2025 were projected at 24,000 MW, representing 80 percent of the current power supplies. Ontario’s energy minister estimated that these investments would cost $25 billion to $40 billion (Canadian) ($18 billion to $29 billion U.S.).
Originally scheduled for shutdown by 2007, the majority of Ontario’s coal-fired capacity will remain on line until 2009. This decision by Ontario’s liberal government represents a reversal of a key election promise to close more than 6,400 MW of coal capacity by 2007. A recently released report by the Ontario Independent Electricity System Operator (IESO) (see Figure 1) recommends that coal generators be available for a period of time even beyond 2009.2 Reasons include the need for reliability support and backup emergency capacity, in addition to accommodating schedule delays for replacement capacity. Some of the planned replacement capacity additions already have run into delays and cancellations—the refurbishment of Pickering’s nuclear units 2 and 3 and one of the previously approved gas-fired units, Greenfield North, have both been canceled. The pressure also has intensified because Ontario last summer set new records for its peak load, exceeding previous records by about 1,500 MW, or 6 percent. These recent developments may lead to further delays in the shutdown of Ontario’s coal-fired assets.
In the Ontario government-instigated supply mix study, OPA recommends that renewable resources and energy conservation meet the majority of Ontario’s load growth by 2025. OPA indicates that renewable resources (including hydro power) would need to increase their presence in the capacity mix from the current 26 percent to 37 percent by 2025. Further, OPA recommends that the contribution of natural gas to the installed capacity mix grow from 16 percent in 2005 to 27 percent by 2025. Further, the study points out that the less severe environmental impacts and lower variable costs of nuclear capacity make it a more suitable source for baseload generation as compared with natural gas. The study encourages the province to expand its nuclear fleet through refurbishing existing units or building new plants, whereby Ontario would continue to rely on nuclear capacity for 50 percent of its energy requirements.
Encouraged by the squeeze on coal, Kyoto Protocol pressures, volatile natural-gas prices, and the province’s renewed desire to become more self sufficient as a result of the power blackout of August 2003, there has been a resurgence in interest in nuclear power. Ontario’s energy minister, Dwight Duncan, says that in any overhaul of the power sector, the province would have to consider nuclear energy. That said, the industry faces an uphill battle given its track record—after several units were shut down seven years ago for safety reasons, and subsequent efforts to refurbish the units and bring them on line again have resulted in cost overruns.
The Ontario market opened for wholesale competition in May 2002. Unlike its neighbors to the south, IESO has yet to adopt a nodal LMP-based market approach and relies mostly on bilateral transactions handled outside the ISO-operated markets.
The Ontario market covers the entire province of Ontario. The market has significant links into the Michigan and New York systems on the U.S. side and is a net supplier of electricity to U.S. consumers. Since markets opened to competition in 2002, power prices have remained moderate but volatile, the latter due to relatively small amounts of power traded in observable markets. There is no formal day-ahead market for power, and the IESO markets are primarily for balancing energy and ancillary services.
Ontario has the largest population in Canada but holds the second spot in terms of electricity market size with a winter and summer peak demand of approximately 25,000 MW. Like most other Midwest and Northeast systems in the United States, Ontario experienced record demands for electricity in the summer of 2005. A peak of 26,160 MW was observed on July 13, about 3 percent above the previous record set in 2002. In fact, this past summer, the previous 2002 record was exceeded during nine days in June and July, putting the Ontario system to the test, and although the IESO did not have to resort to rolling blackouts, the systems operator reduced the voltage on a couple of occasions to conserve capacity. Ontario has 30,520 MW of generation capacity. Nuclear capacity comprises 36 percent (10,850 MW) of total capacity. Coal and hydro each command 25 percent shares of total capacity, with oil and gas comprising the bulk of the remaining capacity (14 percent).
Most of Ontario’s transmission system (97 percent) is owned by Hydro One, another Ontario Hydro successor company—and also owned by the provincial government. The system, however, is managed and operated by the regulated, non-profit IESO. The IESO is a participant in the Northeast Power Coordinating Council (NPCC), and therefore operates the system in compliance with NPCC (and NERC) standards. Ontario is relatively well interconnected to neighboring jurisdictions. In order of importance, Ontario is interconnected with Michigan, New York, Québec, Manitoba, and Minnesota. Table 1 summarizes the main characteristics of today’s market.
Current Status of the IESO
The main issue for the IESO over the next five years is no doubt how to deal with reliability while closing down all coal-fired plants. These closures, an election promise from the sitting Ontario government, are driven in part by a desire to reduce emissions of NOx and SO2 and in part by Canada’s commitment under the Kyoto Protocol to reduce greenhouse gases. All of Ontario’s coal-fired capacity, more than 7,500 MW, is targeted to be closed in this decade, with the first plant (the 1,148-MW Lakeview station) already closed in April 2005. Other closures are scheduled for 2007-2009. As a means of replacing this capacity, the newly created OPA is contracting for refurbished and new capacity using an RFP process. So far, about 2,400 MW of capacity has been awarded for the construction of five new plants: Greenfield Energy Center (1,015 MW); St. Clair Power (688 MW); Greater Toronto Airports Authority (117 MW); Greenfield North (330 MW); and Greenfield South (284 MW). The Greenfield North project however, was canceled in August of 2005. In addition, 10 MW of demand response has been awarded.
Further, in April 2004, the Ontario government initiated a renewable energy supply (RES) program that aims at a substantial increase in the use of renewable energy. The Ontario RES program involves renewable resource targets of 5 percent (1,350 MW) and 10 percent (2,700 MW) of Ontario’s generating capacity by 2007 and 2010, respectively. To this effect, 395 MW of renewable capacity additions were awarded in November 2004 as a result of an RFP process.
Two more RFPs were issued in April and July of 2005 to procure another 1,200 MW of renewable capacity. An agreement also was reached between the units’ operator, Bruce Power, and the government in October 2005 to re-start the nuclear Bruce A 1 & 2 units. This agreement will provide about 1,540 MW of laid-up nuclear capacity that is targeted to come on line by 2010-2011.
After a brief and unsuccessful period of deregulated retail rates in 2002, the Ontario market returned to fixed rates in 2003 and 2004. However, customers with a load in excess of 250,000 kWh per year still pay the wholesale market price. In April of 2005, a new retail rate structure became effective that ties the consumer electricity rates tighter to the cost of generation while still keeping rates under a regulated umbrella. This was done by the new electricity regulated price plan (RPP) determined by the Ontario Ministry of Energy (OME). RPP prices are calculated by the Ontario Energy Board (OEB) using the following components:
• OEB’s forecast of the Ontario spot-market price of electricity over the next 12 months;
• Prices set by the OEB for Ontario Power Generation’s (OPG) regulated (as of April 1, 2005) nuclear and hydroelectric generation facilities (currently an average 4.5 cents/kWh based on projected operating costs plus a 5 percent return on equity);
• Prices the Ontario government will pay under long-term power supply contracts with private generators over the next 12 months; and
• The estimated value of difference that is expected to result from the government’s decision to impose a 13-month (April 1, 2005-April 30, 2006) revenue limit (4.7 cents/kWh) on most of the output from OPG’s unregulated assets.
Current prices established by OEB are intended to remain in place for approximately one year (April 2005 to April 2006). At the end of this period, and every six months thereafter, prices consumers pay for electricity may change based on an updated OEB forecast. The RPP also allows for unscheduled price adjustments to deal with the effect unanticipated circumstances could have on prices.
IESO Market Design
IESO is tasked with managing and operating the grid and wholesale marketplace, and is regulated by OEB. The two key focal areas that encompass IESO authority are:
• Ensuring the reliability of the integrated power system; and
• Overseeing the IESO-administered wholesale markets, including the real-time energy and operating reserve markets.
The real-time energy and operating reserve markets are electricity markets administrated by the IESO, which, for purposes of submitting and revising dispatch data, operate in advance of, and up to, the dispatch hour. Based on this dispatch data, the IESO determines dispatch instructions for each registered facility and boundary entity as the primary means of coordinating the operation of the physical markets during the dispatch hour.
Every five minutes the following real-time market prices are determined:
• Single market clearing price (MCP) for Ontario region; and
• Separate MCPs for energy at each of the 12 intertie zones with neighboring markets.
In addition to the five-minute prices, each hour a calculation is performed to determine the Hourly Ontario Energy Price (HOEP). HOEP is determined by using the average of the five-minute Ontario energy prices. HOEP is used as the wholesale price for electricity for non-dispatchable generators and non-dispatchable loads.
The IESO administers three separate real-time operating-reserve markets to provide a market-based way for the IESO quickly to replace the supply of electricity for a short period of time until requirements can again be supplied from normal dispatch:
• 10-minute synchronized reserve (also called 10 minute spinning);
• 10-minute non-synchronized reserve (also called 10-minute non-spinning); and
• 30-minute reserve (non-synchronized).
In May 2006, the IESO began testing its new “day-ahead commitment process,” which the grid operator plans to implement for an initial six-month run on June 1. The process is seen as a step toward a formal day-ahead market. The IESO implemented an initial 6-month run starting June 1, but it will not be used past Nov. 30 without IESO board approval.
The only financial market operated by the IESO is the transmission rights (TR) market that allows market participants to hedge for congestion across certain paths. The TR is directional and allows its holder to collect congestion revenues whenever prices between the injection node and the withdrawal node are different. The TR also is an option and unlike financial transmission rights in some U.S. markets cannot take on a negative value.
1. Ontario Power Authority: Supply Mix Analysis Report, December 2005.
2. The Ontario Reliability Outlook, IESO: February 2006.