America's Canadian Problem

U.S.-Canada electricity trade is shrinking, and some American companies may be left without their megawatts for the summer.
Fortnightly Magazine - April 15 2003

U.S.-Canada electricity trade is shrinking, and some American companies may be left without their megawatts for the summer.

The megawatt flow to the United States from Canada is winding downward despite the continuing U.S. requirement for substantial peak demand, energy experts say. This downward trend in cross-border electricity trade is due in large part to rising demand from Canada's economic growth. And with more natural gas-fired generation starting up on both sides of the border, signs also indicate that during the rest of the decade, the United States and Canada increasingly will become less dependent on one another for peak demand electricity needs.

Traditionally, as U.S. summer peak demand drives the market to attractive, if not volatile, pricing levels, Canada exports between 6 percent and 8 percent of its total electricity generation to a host of U.S. states. Then, during the winter (Canada's peak demand period, except for heavily air-conditioned Ontario), U.S. generators export electricity across the well-connected border to the north, in a natural complement of seasonal trade.

Last year, Canada exported a total of 36.7 million megawatt-hours (MWh) to the United States, at an average price of Cdn$46.00 (about US$30.00) per MWh, according to statistics compiled by Mary-Jane Sam, the statistical research officer in the Commodities Business Unit at Canada's National Energy Board (NEB), in Calgary. And in 2002, Canada imported 13.9 million MWh from the United States at an average price of Cdn$36.18 per MWh. This trade resulted in a net Canadian export of 20.8 million MWh, which netted some Cdn$1.4 billion, mostly for hydroelectric generators, which purchase electricity from the United States when prices are low and pump water up into reservoirs with available capacity.

Comparing 2002 trade with 2001, net U.S. imports are down. During full-year 2001, Canada exported 40.1 million MWh at an average price of Cdn$100 per MWh, while importing 17.9 million MWh at an average price of Cdn$101. The net result in 2001 was 22.3 million MWh of Canadian exports worth Cdn$2.4 billion.

Looking forward for at least the mid term, the trend in net imports by the United States will continue downward, says Ivan Harvie, a senior engineer at the NEB, in Calgary. "The number one reason why trade will decline is that 70 percent of Canadian exports come from hydro and it takes many years to bring on new hydro capacity. So as the demand load grows in Canada, it will leave less available for exports to the United States," he says.

Keeping pace with demand growth in both the United States and Canada was once a higher strategic priority for Canadian generators. "There was a time when Ontario wanted to develop as a hub for the (cross-border) region and be a big player in the export market; they even were looking at buying transmission assets in the United States. But after the Enron and California effects, the exuberance has dropped off," Harvie says. According to a recent draft NEB analysis of Canada's future energy demand through the year 2025, total electricity exports are projected to drop to less than 4 percent of total electricity generation, or about half the historic level.

Peak Demand Problems in Ontario

Ontario in particular is driving up peak load during the summer months, when North American prices are at their highest. In August 2002, Ontario logged an all-time peak of 25,414 MW. As a result, other provinces, including neighboring Quebec-the largest electricity exporter to the United States-supply Ontario during the summer, thus reducing available energy for export.

Ontario is not building enough new capacity to end its peak demand problem anytime soon, one analyst suggests. "The Ontario market is forecast to have a capacity shortfall as early as 2005, even with the 3,500 MW of nuclear capacity that is scheduled to return to service and with the 1,000 MW of independent generating capacity currently under construction," says John Dalton, a managing director at Navigant Consulting in Toronto. The timetable for the return of the nuclear plants could suffer from political factors as well as mechanical factors, however, further exacerbating peak load problems in Ontario.

Quebec leads Canadian provincial exporters, having sold 14.7 million MWh to the United States last year, followed by British Columbia with 7.9 million MWh, Manitoba with 7.4 million MWh, and Ontario with 2.4 million MWh. None of the other provinces that exported to the United States last year, including Alberta, New Brunswick, Nova Scotia, and Saskatchewan, sold more than a few hundred thousand megawatt-hours.

Still, Newfoundland and Labrador could become substantial exporters if negotiators agree on the terms of the proposed Gull Island hydroelectric project. This 2,000 MW project is located on the Churchill River in Labrador and carries an estimated cost of Cdn$4 billion for the construction of the dam and a transmission line to Ontario; completion is estimated six years from construction start. "At least initially, some of the electricity from Gull Island could be exported," Dalton says.

The states that imported more than 1 million MWh from Canada last year, according to Sam's NEB statistics, include:

  • New York with 13.9 million MWh;
  • North Dakota/Minnesota with 7.4 million MWh;
  • Washington with 4.4 million MWh;
  • Maine with 3.9 million MWh;
  • Vermont with 2.1 million MWh;
  • California with 1.9 million MWh; and
  • Oregon with 1.5 million MWh.

While the volume of Canadian electricity supplied to the United States as a whole may be diminishing, much of the current supply will continue to be a critical component in the planning for energy-short regions like New England. In an October 2002 projection of the next four years' worth of demand and supply for the New England Power Pool (Nepool), ISO New England has modeled summer peak month supply plans that include a flow of 1,450 MW from Hydro Quebec and New Brunswick, the lion's share of all planned purchases for Nepool.

U.S. Supplies Provinces, but Deregulation Inspires Little Cross-Border Trade

A few states are major exporters of electricity to Canadian provinces, mostly during the winter months. In 2002, Washington led all state exporters with 5.6 million MWh sold to Canada, followed by New York with 3 million MWh and North Dakota/Minnesota with 2.1 million MWh, NEB statistics show.

Given the plethora of merchant plant projects that have been funded over the last several years in the United States, it seems likely that some U.S. states along the Canadian border could compete with gas-fired generators in the provinces for peak load demand in Canada, since transmission costs could be similar. U.S. gas-fired projects obviously cannot compete with Canadian hydro projects, given current natural gas prices. But natural gas seems to be the preferred fuel source for the planned conversion of many of Canada's coal-fired units, which could further level the cross-border playing field for trade in gas-fired electricity generation.

Yet with the advent of Canadian deregulation, the number of marketers there has risen dramatically, which nominally would permit the number of significant exporters to rise as well. But only a handful of the largest hydro-based utilities control most electricity exports. "We used to have just a few provincial players in the market, but in the last 10 years, we've had about 40 new marketers enter, so there is a lot more trading back and forth. Still, the total volume of exports by those 40 is less than 1 percent of the total of cross-border trade," Harvie estimates.

The failure of the new marketers to gain a stronger foothold in the export market may have more to do with regulation than with competition, though. "The electric utility industry restructuring that has taken place over the past decade has not resulted in increased Canadian electricity exports; indeed, exports have declined since the mid-1990s," Harvie says. On the other hand, U.S. deregulation has helped standardize the North American regulatory norm, others suggest. "Dozens of Canadian companies have made submissions to the FERC on standard market design, because they don't want to see any trade barriers," one consultant says.

Canada's unbundling of still-regulated transmission from distribution and generation, however, may help the export potential over the mid to long term, since transmission capacity is one limit to cross-border trade growth. But investments in generation in provinces like Ontario, where a retail electricity price cap has been imposed through 2006, could discourage enough investment to preserve the province's peak demand problem for years to come.

Whether sufficient utility capital resources will be available to make needed investments in generation and transmission also is an open question, given Canadian regulations, which permit high levels of utility debt. Standard & Poor's is reanalyzing the impact of regulation on the credit ratings of Canadian utilities, with an eye toward the possibility of higher, investment-grade ratings. Nonetheless, "Investor-owned Canadian utilities are among the most highly-levered utilities in S&P's global ratings universe, with financial profiles that are noticeably weaker than those of their global peers," notes Thomas Connell, a credit analyst at S&P in Toronto. "Many Canadian utilities typically have lower equity layers in their capital structures than their global peers, with total debt in some cases representing 60 percent to 70 percent of total capital," he said in early March.

The retail price cap in Ontario has had a singularly negative impact on investment in new generating capacity in the province, Dalton says. "Conditions in the power markets make the development of new capacity particularly difficult. These conditions include the retail price freeze imposed by the Ontario government in November 2002 which adversely affects investor confidence, the financial woes of merchant generators which make equity investments difficult, and lenders' requirement that the output of new generators be largely contracted," he says.

Alternative Fuel Sources: Does Canada Have More To Give?

Nonetheless, Canada is rich in energy resources and the hydroelectric potential that could generate much more electricity. Canada's hydropower association suggests that the country still has twice as much hydroelectric potential as the 50,000 MW that already have been developed, representing almost a third of all generation capacity in the country. But the long lead-time in constructing a hydro facility typically requires long-term purchase contracts, which are no longer a staple of the market. Thus, electricity generated from nucle-ar, natural gas, oil sands, coal, wood, and wind sources could gain a larger share of the total Canadian generation volume.

One major new alternative fuel project in the early stages of development is based in oil sands-rich Alberta. Northern Lights Transmission hopes to construct a direct current electricity transmission line from Alberta to the U.S. Pacific Northwest for electricity export by 2008. The electricity the line would carry would be generated largely from cogeneration units, which also would produce the steam used to recover oil from the sands. The planned capacity of the 1,000-mile long transmission line is 2,000 MW, plus or minus 500 kilovolts. Feasibility studies under negotiation are assessing routing alternatives for customers in Canada and in the United States, as well as potential investors, says Glenn Herchak, a spokesman for TransCanada, in Calgary, the lead developer of the project.

The oil sands project could be important for Canada's total energy trade balance, because Northern Lights is projected to be capable of producing more than 300 billion barrels of oil, a volume which is 40 billion more barrels than is recoverable in the Middle East and 14 times more than the recoverable oil that exists in the United States, the developer claims. Northern Lights Transmission currently is a partnership between Trans-Canada and AltaLink; AltaLink is a consortium comprising SNC Lavalin Energy, Trans-Elect Inc., Ontario Teachers' Pension Plan, and Macquarie North America Ltd., a subsidiary of Macquarie Group of Sydney.

Including the oil sands project, Alberta generators have proposed construction of more than 5,000 MW of new electricity generation by 2005, which would far exceed expected demand and would permit the export of some 3,000 MW, according to provincial projections.

Nuclear generation already is key to some importing provinces, like Ontario. In a January 2003 projection of supply and demand for the following 18 months, the Ontario Independent Electricity Market Operator notes, "More significant than the demand changes are the delays announced in October (2002) to the restart of the shut down Pickering A nuclear units. These delays have reduced available generation substantially over the entire outlook period. … If the Pickering and Bruce nuclear units do not return to service as scheduled before next summer, supply will continue to be stretched thin."

Nuclear power could provide a growing share of electricity in Canada, where political opposition to the fuel source seems less vociferous than in the United States. In Ontario, for example, the restart of the twin 750-MW Bruce Power plants has been scheduled for April and June of this year. "In the Ontario market it is anticipated that 3,500 MW of nuclear power will be returning to service over the next three-plus years, so if all that returns, during off-peak we would expect Ontario would go from a net importer to a net exporter," Dalton says.

Still, in some provinces, nuclear power is less welcome. In British Columbia, a new energy policy unveiled in November 2002 indicates that nuclear power will not be permitted in the province. This could suggest that in provinces where hydro- traditionally a publicly managed asset-is a strong option for new capacity, neither publicly nor privately financed nuclear projects may be feasible.

Similarly, a host of gas-fired plants also are scheduled to open across the country over the near term. In power-hungry Ontario, for example, the 578-MW ATCO Brighton Beach unit is scheduled to come on line in March 2004, and the smaller 98-MW Imperial Oil unit is slated for an April 2004 startup.

Merchant Plants To Gain Ground

Since the California debacle, private financiers' enthusiasm for merchant plants has waned in Canada, one source says. Cost recovery is the key. "From East to West there were a lot of merchant plant proposals, but there is not much activity now, and the biggest hurdle is firm contracts," Harvie says. But the provinces still are willing to sign longer-term contracts that can make merchant plants viable, given the province's responsibilities to its citizens.

In electricity-export-strong Quebec during 2002, the total volume supplied by purchase contracts with independent power producers amounted to only 387 MW. Hydro Quebec estimates that over the next few years, there will be only an additional 48 MW available from IPPs.

Similarly, in British Columbia, Canada's other export powerhouse, the province just recently decided to allow private sector participation in the development of generating assets in general, with the proviso that no more large-scale hydro projects will be approved.

Other provinces are less sanguine about the potential role of private sector equity in any hydroelectric projects. "Some provinces don't want to broach the subject of private money in hydro. Some provinces don't want to even go there. The politician who does bring it up doesn't want to stay in office very long," suggests one analyst.

While the mid-term outlook for U.S. imports of electricity from Canada is down, the longer-term view is somewhat brighter. Several new generating projects in Canada could breathe new life into exports to the United States. While some of these projects are based on merchant plant financing, others are expected to involve a higher level of provincial government capital, mitigating the risks resulting from the dearth of new long-term purchase contracts available in the North American market. And although Canadian generators depend mostly on hydroelectric potential for export sales now, an evolving mix of fuel sources also could help yield more exports, analysts say. Finally, new Canadian transmission assets under consideration could better link several provinces to the U.S. grid and help make Canadian electricity more competitive with U.S. generation.

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