Energy Probe

Tom Adams
Toronto Star
January 8, 2002

Re Harris irresponsible to deregulate hydro
Dec. 20.

In arguing against restructuring Ontario’s power system, the Star opines: "It isn’t as if Ontario is experiencing an electricity crisis."

The Star might remember that, in 1997, Ontario Hydro announced that it was unable to meet the financial requirements of our governing electricity legislation, effectively declaring the public sector equivalent of bankruptcy.

In 1993, then Ontario Hydro chairman Maurice Strong accurately forecast this collapse, telling everyone who would listen that Ontario Hydro was "a corporation in crisis."

The deteriorating financial condition of our power system is by no means the whole extent of our crisis.

Government-funded megaprojects have created some of Ontario’s worst environmental problems, too.

If the Ontario government can be forced to stick to its promise that taxpayers will no longer be involuntary investors in electricity investments, our environment will heave a sigh of relief.

Although there are many legitimate reasons to criticize Mike Harris’ electricity structuring — rising taxpayer liabilities to pay for nuclear expansion, continuing subsidies for industrial power guzzlers and unnecessary 70 per cent increases in distribution rates are only a few examples — on balance, the restructuring’s merits — like breaking down bills into the constituent costs, opening the transmission system to competitors and introducing regulation for monopoly elements of the power system — outweigh the disbenefits.

Tom Adams
Executive Director
Energy Probe
Toronto

Tom Adams

January 16, 2002

Energy Probe Ontario Electricity Backgrounder

The Ontario government has issued regulations that will guide the administration of its new electricity tax called the Debt Reduction Charge, regulations that are consistent with its 1997 commitment to ensure fairness to all classes of customers in the recovery of financial liabilities left over by Ontario Hydro. (See O. Reg. 493/01, Ontario Gazette, January 5, 2002.)

The Debt Reduction Charge was first introduced in June 2001 and has been set at 0.7 cents/kilowatt-hour, or about 10% of the cost of electricity. Most of the liabilities that the proceeds of the Debt Reduction Charge will help to pay down relate to historic nuclear costs with a much smaller portion attributable to long-term power purchase contracts at above market prices.

In its 1997 White Paper on electricity reform, the Ontario government promised that any special debt recovery payments would be administered so as to be "clear and fair to all customer classes." The new rules will ensure that large industrial customers capable of generating their own power will not be able to use that capability to escape paying electricity taxes. Instead, all electricity consumption in Ontario will be taxed, irrespective of whether the power is bought through the grid or generated internally.

The only customers excused from paying their share of the Debt Reduction Charge are a secret group of heavy industries who have special rate discounts originally granted by Ontario Hydro and extended for up to four years into the new market. Ontario’s electricity reform legislation passed in 1998 promised to eliminate all special rate discounts upon market opening.

Communities or industries that have historically generated some of their own power, or through alternative purchasing arrangements did not buy electricity from Ontario Hydro, will have their Debt Reduction Charges reduced or eliminated.

In 1995, during the deliberations of the Advisory Committee on Competition in Ontario’s Electricity System, chaired by former federal finance minister Donald Macdonald, the lobby group speaking for heavy industry, called AMPCO, expressed the view that the historic liabilities of Ontario Hydro should be recovered from all consumers fairly, including heavy industry. That commitment would help to create an atmosphere of consensus around the electricity restructuring, a concensus that for the most part held until mid-2000.

Prior to and throughout Ontario’s electricity restructuring process, Energy Probe has recommended that, for efficiency and accountability reasons, the liabilities of the former Ontario Hydro that cannot be recovered through ordinary electricity rates should not be recovered in electricity taxes but instead should be recovered from taxpayers. Ontario Hydro’s borrowing was protected by provincial loan guarantees.

Scott Anderson
Now
January 17, 2002

A power war is being waged on doorsteps all across the city. Local and multinational electricity retailers are aggressively trolling for customers, trying to sign up as many as possible before the competitive market opens on May 1.

In the middle of the free-market frenzy is our newly reformed, publicly owned Toronto Hydro, mandated to champion green energy – and now expected to be a money spinner for City Hall as well.

But can the company be both? Can Toronto Hydro succeed in the cutthroat free market and at the same time lure consumers away from cheap and polluting nuclear and coal-fired energy? The company, not to mention its co-chair, councillor and environmentalist Jack Layton, believes so.

But another local ecologist and energy specialist, Tom Adams of Energy Probe, thinks Toronto Hydro’s just posing green. "When Toronto customers are signing with Toronto Hydro, what they need to know is that they are promoting (nuclear) power," says Adams. "So much for Toronto Hydro’s green credentials."

Adams is referring to the fact that the electricity Toronto Hydro currently sells to city residents and businesses comes from the provincial power grid, which includes 39 per cent nuclear power, 32 per cent fossil fuel (6 per cent natural gas, 26 per cent coal), 27 per cent water power and 2 per cent alternative sources like wind and solar.

Layton insists that the provincial government has left Toronto Hydro with no choice. "They’ve left us with coal-fired plants that are absolutely filthy. We could have bought more power from coal-fired plants , but then we’d be killing even more Torontonians. Unless we have alternate sources of power, we have to turn to nuclear in the interim and Niagara Falls and the other baseline services that we’ve got."

But the public company says it’s committed to becoming the province’s leading promoter and producer of green energy. On the agenda: the construction of a gas-powered co-generation plant in the port lands, two wind turbines (one at the CNE and the other at Ashbridges Bay), harnessing methane gas from the city’s Thackeray landfill site, as well as a solar hot water pilot project and an anaerobic digestion plant that will convert compostables into energy.

Sounds great. But will those initiatives make a dent in the market?

The co-gen plant planned for the port lands won’t be operating before the end of 2004, and Toronto Hydro can’t say how much power it will produce. The financing for the project has yet to be secured. And even if Toronto Hydro and its corporate partners get the plant up and running, there’s no guarantee they will be able to sell the power at competitive rates.

"It’s got real environmental benefit to it," says Toronto Hydro Corp vice- president Blair Peberdy. "The challenge is, though, can (Hydro) produce power out of there that’s competitive?"

Toronto Hydro says the wind turbines and landfill gas site will be online later this year. But, combined, they will only produce enough power for 1,150 households.

Adams says it’s all good PR for Toronto Hydro but won’t capture the market from coal and nuclear power.

"Landfill gas, run of the river, solar on your rooftops and windmills basically don’t count if our strategy is to try to get rid of coal , because putting all of these things together is just not going to make a difference," says Adams. "The combination of (low) output and (high) cost makes it a non-viable strategy."

Adams says Toronto Hydro is not focusing enough on buying or producing lots of cheap energy from co-generation. "The point is, we can do co-generation on a massive scale," he says. "The TransAlta project (a private co-generation facility being built in Sarnia) is going to be generating the power of maybe 1,500 wind turbines."

While Layton and others on city council are using Toronto Hydro as a tool for changing energy consumption, councillors also expect it to be a cash cow. And the company can only do that by selling competitively priced energy.

Toronto Hydro Electric System, the offshoot that services and maintains the city’s power lines, pays $60 million back to City Hall each year. The city uses this money to offset capital costs.

As well, Toronto Hydro Services Energy, the newly formed retail arm, will also be expected to provide dividends to the city once the market opens and it starts selling.

Adams argues that this creates "some risks for municipal democracy" because "a lot of the city’s expenditures are reliant not on taxpayers, but ultimately on electricity ratepayers."

But Layton disagrees that there will be pressure on Toronto Hydro from council to be profitable first.

"Our view is that if our company is not advanced environmentally, then whether or not we should have a public energy company would come into question," Layton says. "I think council is interested in having such a company, in part to advance the sustainability agenda. That’s certainly what I’m doing on the board."

Tom Adams’ response to this article:

Now magazine missed the worst part of Toronto Hydro’s green scam. As I told your reporter, notwithstanding its pretty pictures of a few token wind turbines, the high-priced electricity contracts that Toronto Hydro is foisting on an unwitting public are backed to a substantial degree by supply contracts with Bruce Power. Toronto Hydro is directly and by choice financially supporting Bruce Power’s activities, which include the restart of two dilapidated reactors at Bruce A.

Once, before our city had dollar signs flashing in the eyes of its utility, our city government took a noble stand against nuclear insanity, backing a constitutional challenge against the Nuclear Liability Act, a law that shields nuclear operators like Bruce Power from liability in the event of accidents. Now, in its electricity contracting, Toronto Hydro has no higher standards than the multinational-backed Direct Energy, which is also helping nuke Bruce. So much for Toronto Hydro’s green credentials.

January 17, 2002

  Summary and update on Energy Probe’s expectations for consumer electricity price changes related to Ontario’s electricity market restructuring

Energy Probe believes that, comparing overall bills before April 1, 1999 with bills after all the changes currently decided are fully implemented, bills for ordinary household consumers (1000 kWh/mth) who don’t sign contracts with marketers are likely to rise by at least 20 per cent. Contributing factors in both the upward and downward directions are:

• The Ontario Energy Board PBR Rate Handbook decision that increased distribution rates by 60 to 70 per cent. Some of this increase has already been implemented in many areas of Ontario.

• Double recovery of the Debt Reduction Charge for the period June 2000 to April 2001.

• Payments in lieu of taxes that will soon be paid by distribution utilities to Ontario Electricity Financial Corporation (OEFC).

• Net load billing for network transmission as decided by the Ontario Energy Board and net billing for IMO fees as decided by the IMO (the largest elements of which are recovery for out-of-merit dispatch costs and costs for ancillary services) both of which will transfer costs from large industrial customers with load displacement generation to smaller customers.

• The unfavourable net system load shape of small customers who don’t have access to interval metering.

• The impact of the government’s decision to grandfather special rate discounts to a secret group of Ontario’s largest industrial electricity consumers (primarily felt by customers through reduced MPMA rebates and longer recovery period for DRC).

• The recovery transition cost incurred by all components of Ontario’s former electricity system.

• Based on current pricing trends in the New York and PJM markets, in the near term, overall commodity prices are likely to decline, offsetting somewhat the impact of the above factors.

Energy Probe estimates that those with marketer contracts are going to see a further increase over their current embedded commodity-only rates (not bills) of 19 per cent to 42 per cent.

Further significant upward price pressures appear to be coming but their magnitude is uncertain. The unfunded stranded debt is bigger now than at April 1, 1999. The government’s claim, repeated in OEFC’s most recent financial statements, that the unfounded stranded debt will be eliminated by 2010-2017 is unlikely to be sustained. Not only is the sign on the stranded debt recovery cashflow negative for the first two years taken together but we suspect that the estimate for the stranded debt is understated. The prevailing official stranded debt assessment took the Ernst & Young audited nuclear liability figures from the old Ontario Hydro at face value. We believe that the E&Y approach suffers from a number of flaws which understate the liability – particularly related to the generator in-service period estimate, the generator load factor estimate, and the adherence to a volumetric recovery mechanism. Eventually, we anticipate that taxpayers will get hit for at least some of this. (Note that contrary to the provincial Auditor’s statements, the taxpayer has already starting paying electricity costs since the $520 million owing annually to OEFC from the province is not being recovered in dividends from OPG and H1. Not including the cost of electricity consumed in government operations, taxpayers paid general electricity costs of $235 million in f2000 and $54 million in f2001.)

February 1, 2002

UK industrial electricity prices

The Electricity Association also tracks prices to customers in the industrial sector. In order to ensure that calculated results are consistent in methodology, comparable over time, and to act as a basis for comparison with other countries, three benchmark loads are used. Each benchmark has its own defined levels of maximum demand and load factor to give a standardised consumption pattern. The benchmarks are as follows:
 
 

* load factor is defined as the ratio of the average load, during a specified period, to the maximum load (maximum demand) during that period. Using these models and historic tariff and contract prices, we have compiled a table of final-user industrial prices.
  Annual Average Results
 
 
 

1) Source: Electricity Association’s International Electricity Prices Surveys (IEP).
Averages for 1989/90 include data not published at the time because of the privatisation process.
2) Tariff prices (tariffs were generally applied until March 1994).
3) Tariff prices (tariffs were only applied to this type of load until March 1990).
4) Special-terms prices (such terms were only applied until March 1990).
5) Retail Prices Index.  
 

International Electricity Prices

The Electricity Association also carries out an annual survey of international electricity prices, to provide an indication how UK prices compare with European and world electricity prices. Each survey is a snapshot of prices at 1 January. The results take several months to compile and the last results available are for the survey dated 1 January 2001. Following below are highlights and press release extracts from the launch of the survey’s results.
  UK Electricity Still Among EU Cheapest After Further Prices Falls

Domestic power prices are the fourth lowest among the EU member countries, as detailed in the new edition of the EA’s annual worldwide comparative survey, International Electricity Prices. Despite the strength of sterling against the Euro, the survey shows that prices for a typical domestic customer in the UK have fallen 9% in real terms since the previous survey, to 7.51 pence per kilowatt hour.  This means that UK customers enjoy prices up to 42% cheaper than in other parts of the EU.
 
  In the industrial market, prices under contract are also good value.  Prices for a typical medium-sized industrial user are 3.95 pence per kilowatt hour, compared with 6.6 pence in Italy, the most expensive in Europe.

February 1, 2002

  Privatization, Market Pricing, and Restructuring in Ontario
Tuesday, Feb. 26, 7:30-9:30 p.m.
ADMISSION IS FREE

Download flyer:link inactive http://www.stlc.com/forums/StLC%20Electricity.pdf

St. Lawrence Centre for the Arts
27 Front Street East, Toronto
(Two blocks south of the King Street subway station, one block east of Yonge Street.)
Seating is limited to 500, first come first seated.

On May 1, the Ontario Government plans to open our electricity market to competition. They have begun leasing and selling 65 per cent of the power generating capacity of Ontario Power Generation, and plan to sell Hydro One. Both were formerly part of Ontario Hydro. New regulations have been introduced and more are coming. What does all this mean for your taxes and hydro bills, the environment, and the reliability of electricity in the province? The cost of electricity impacts everything from the production of goods and services, to home and commercial utilities, and jobs.

Will the new regulations provide more options for green energy? What lessons can we learn from other jurisdictions, such as California, Alberta, Pennsylvania and the U.K.? What are our choices, and what can we expect?

The Panel:

Tom Adams: Executive Director, Energy Probe; formerly both an independent director of the Ontario Independent Electricity Market Operator and member of the Ontario Market Design Committee.

Howard Hampton: Ontario NDP Leader and Energy Critic; MPP for Kenora Rainy River.

Richard Perdue: member of the Minister of Energy’s Electricity Transition Committee, Director of Enterprise Canada’s energy division; former member of the Ontario Energy Board.

John Wilson: former Engineer, Hydro One; former president of the Society of Energy Professionals.

Sponsored by the St. Lawrence Centre Forum in partnership with the Ontario Electricity Coalition and Energy Probe.

IPPSO FACTO/February 2002 issue
February 1, 2002

Toronto: On January 22, the IMO sponsored an open forum for discussion between its staff and market participants, on priorities for "market evolution." Nearly 100 delegates were able to hear each others’ views and register their preferences about where the IMO should focus its attention in the next two to five years. Issues such as the development of the forward market, integration with grid systems in the U.S., locational marginal pricing, and ancillary services were reviewed. "This is a commendable and crucial exercise, to know if the IMO is focusing on the same things as the participants want it to," said IPPSO Executive Director Jake Brooks.

At the outset, the CEO of the IMO David Goulding identified a range of factors, affecting the long-term development of the market, with many of them in the international context. He confirmed that the market will open on May 1. Then various IMO staff overviewed a range of areas in which the Ontario market may be subject to change: Energy Forward Market; transmission expansion, Demand Side Management, Physical Bilateral Contracts, U.S. developments. The guiding principles for market design endorsed by the IMO Board include the following: efficiency, fairness, reliability, and transparency.

Although true physical bilateral contracts are not possible under Ontario’s market rules, a service similar to physical bilateral contracts for energy is. This service, called physical bilateral contracting, reduces prudentials. Should this billing option be extended to other charges as IMO fees and transmission charges? If such a system were to be implemented, there would be implications for how other charges are allocated, including the DRC, IMO fees and transmission charges.

The IMO’s Darren Finkbeiner explained how the U.S. FERC is trying to come up with one consistent transmission scheduling design that can apply across the country. Manitoba will be effectively a member of the Midwest ISO. Michigan is also indirectly affiliated with it, through the Alliance ISO, which is supposed to merge with the Midwest ISO. The Open Scheduling System (OSS) is trying to make it possible for a single bid or offer to be automatically entered into the tolls of the various markets, to facilitate long-distance transmission. He noted that "We can no longer separate reliability standards from commercial standards," and said that "the Standards will be more cognizant of the commercial activity of the market."

Under Ontario’s market design, Operating Reserve is currently procured by the IMO on behalf of the market participants, and billed for through uplift charges. There were discussions about whether this should be changed. Other services including frequency control, AGC, voltage control, reactive power, and black start capability are procured through a competitive contractual process, but could be procured through a competitive market. There were discussions about whether the four-hour advance requirements for scheduling power with the IMO should be shortened. In Ontario because we don’t have a day ahead market, it’s not clear if shortening the four hour advance requirements will increase or reduce certainty.

With respect to transmission costs, one price for Ontario is now the rule, but the IMO will publish the nodal prices. Congestion costs and transmission losses are currently paid for by the entire market. Nodal pricing is a price calculated at each and every injection and offtake point. The Financial Transmission rights market deals only with congestion on the inter-ties. If you want to hedge your congestion costs between two nodes, there will need to be more mechanisms in the LMP.

Peter Segejweich explained that the capacity reserve market can be activated at any time by the IMO, but that it is currently deferred for at least 12 months. ICAP is an alternative.

Comments from the audience were wide-ranging and thoughtful. Tim Bush, from Sithe Power Marketing, stressed the need for an installed capacity market in Ontario to encourage investment in generation. Otherwise you need an uncapped price to transmit capacity signals and the resulting price volatility is politically difficult, he said. ICAP does not result in higher prices. "It is much easier to capitalize for reserve than to capitalize for volatility," he said. Make sure that price signals occur well enough ahead of time to allow for the investment, he suggested, and noted that an ICAP market in Ontario would be consistent with other markets in the northeast. "ICAP needs to be the top priority as we move forward."

Tom Adams of Energy Probe endorsed an energy-only market, without ICAP. Energy-only markets promote dispatchability, he argued, and enhanced elasticity of demand on the part of consumers can address many of the same things that ICAP does. We do need an energy forwards market, but the IMO is not the best party to pursue it. He also observed that there is a much higher appreciation amongst market participants about the advantages of open electricity borders than amongst the public in general. Many are of the view that we can preserve made-in-Ontario prices. Open borders need more advocates.

Peter Fuller of Mirant Americas Energy Marketing agreed with the need for consultation and evolution of the market, including the harmonization of market designs. He said that we need to be able to import and export the ancillaries too. There is a need for more firm border rights, to allow parties to move with certainty, so that we can hedge against it. He also advocated something commonly raised by generators – the need for a binding day-ahead commitment power supply market with its own settlements – saying it would avoid a great deal of inefficiency that occurs between the day ahead and the real time market. New England has problems because of the single settlement market, which had led to needs for regulatory discipline that would have been better accomplished through market discipline. He also agreed with other speakers that in a market where there are energy price caps, there is a need for another product like an installed capacity market. The benefits will accrue as supply becomes tight. It would give structural certainty to invest in things that support reliability.

Keith Rawson of TransCanada Energy Ltd. also endorsed a "two-settlement market" to match what’s going on in the northeast, but leave the forward market to the private sector. He also noted that some problems with liquidity are caused by OPG’s market power, so we need more power inflow from outside Ontario. TransCanada supports the IMO working on other seams issues.

Mike Kurichuk of Bowater said that participants need to develop additional sensitivity to regional issues. In northwestern Ontario the grid is weak, and participants like Bowater could help with reactive power, if there were appropriate incentive in place. Stakeholders should be consulted in the development of regional LMP zones.

Mike McDonald of PG&E Energy Group said that his company supports LMP and the development of the day-ahead market, as part of the energy forward market. He noted, however, that the private sector can develop other aspects of the forward market. With reference to the ICAP market, he observed that there is a lot of theory behind an energy-only market, and "I have yet to see any place where the politics do not interfere with an energy-only market."

David Goldsmith of IVACO, a major energy consumer, put his emphasis on the development of an energy forward market, because assuming there is reasonable liquidity, it allows for price transparency. Encouragement of dispatchable load is important to counteract generation market power, he noted.

Jim Richardson of Tay Hydro suggested that the market has been supply-focsued. "Until we have both supply and demand engaged, we don’t have a real market." The demand side can be responsive to prices. Instead of a capacity reserve market, we should have interval meters on the load side, he suggested.

Darius Vaiciunas of Collus Power Corp. in Collingwood, echoed some of the comments of Jim Richardson and argued that LMP is no use unless the people in those areas are able to respond to price changes. "Without an interval meter, how are you going to respond?" he asked.

Mike McGee of the Building Owners and Managers Association said there are risks for consumers like his members in making purchase contracts. He said, "We need an element of price discovery," and noted that so far, "We have a lousy retail market." He endorsed efforts to speed development of a forwards market, ICAP, and a day ahead commitment market.

Randy Heaton of OPG suggested that we need to give priority to regional parity in the evolution of our market. In the interest of creating a liquid market and stable price, we need to look towards a two-settlement or some way of reflecting what goes on in the northeast. It’s critical for ongoing reliability.

Jim MacDougall of Toronto Hydro Energy Services agreed that a forwards market is an important tool for price discovery. The IMO may catalyze its development, but should not own it. A day-ahead financial commitment market would give the customer a real price signal that would allow them to adjust behaviour and benefit from load curtailment programs. He agreed with other commentators who didn’t see sufficient immediate benefits associated with moving toward a real-time bidding market, "especially given the dominance of some players in Ontario." ICAP would be an effective mechanism to stabilize Ontario prices, he thought.

James Lee of Nova Chemicals said price and power quality in reliability are the main things. "Transparency, liquidity and efficiency are what we are looking for." We know that of all commodities, electricity has the highest volatility. However we need to mitigate it. Without an ancillary market, what incentive is there to provide that efficiently to the market, he asked, and how are we assured of getting a fair and competitive price for ancillaries as well.

Rob Cary representing Sithe endorsed some earlier speakers’ comments that the IMO should have clear policy objectives in setting its priorities: maintenance of reliability and adequacy; creation of the environment for necessary generation investment; alignment/integration with neighbouring market RTO structures. We also need to bear in mind that some elements that have been identified as necessary for the whole market, such as interval meters, are a retail issue led by the OEB. And the biggest driver in the development of forward markets is the SSS system.

1. The first wholesale market priority needs to be definition of an ICAP market. It needs to be set up well before you would otherwise experience unacceptable shortages, to allow for construction lead times. Firm commitment is needed now to move this forward. 2. At the second level of priority, we need to move now towards a two-settlement market with day-ahead generation commitment. This replaces the day ahead forward market now described in the market rules. 3. The IMO should seek to enable, but not to manage financial forward markets beyond that. Real-time bidding shouldn’t be implemented for its own sake and only after there’s a day-ahead commitment market. 4. Encouragement of load price elasticity has a number of facets: retail price elasticity depends on real-time metering; most of the demand side response is possible with interval metering, and would not need full five minute dispatchability; an ICAP market can also provide economic incentive to recognize interruptibility.

Jan Carr of Barker, Dunn and Rossi suggested three principles to consider in setting priorities: what produces the biggest bang for the buck in terms of waivers, emission trading, etc. "Let’s make sure the horse can run, before we fit it for a new harness," he said.

The IMO asked participants for their suggestions as to how future stakeholder consultations should be organized. General comments included the following: • everyone felt the IMO should continue with these consultations • most felt that all participants and stakeholders should be included/able to participate voluntarily • most expressed support for a well-defined and predictable process • most supported meetings supported by tele-conferencing and the opportunity for written input if unable to participate in person • most felt that a mixture of fully involved meetings (i.e. for design and policy issues) and open representative meetings (i.e. for more technical/procedural issues would be best.

For more information, visit the IMO Web site (the discussion paper on market evolution is available there) or contact the IMO at imo.consultation@theimo.com.

Paul Vieira
Financial Post
February 15, 2002

The electricity deregulation debacles in California and Alberta should not deter other provinces, such as Ontario, from reforming their power markets, a C.D. Howe study suggests.

If reforms are implemented properly, the benefits are plentiful, writes the study’s author, Mark Jaccard, a professor of environmental management at Simon Fraser University in Burnaby, B.C.

"The difficulties of California . . . and Alberta send a clear warning about the perils of electricity market reform, especially about the assumption that electricity can be treated identically to other commodities," Mr. Jaccard said, describing power as an "unsubstitutable" commodity.

"[But] the risks of the monopoly models are great," he added. "The monopoly model saddles all [taxpayers] with these risks, instead of allowing private investors to play a risk-taking role," noting that Ontario Hydro’s experience with nuclear power is a clear illustration.

But the study’s recommendations to prevent California-type replays drew some criticism. And it also failed to analyze or evaluate how Ontario’s deregulation will proceed.

Ontario will open its $10-billion electricity market to competition on May 1, and critics say electricity rates will skyrocket, much as they did in California and Alberta. Deregulation opponents say price hikes of at least 20% are in the offing, while Mike Harris, the province’s Premier, says he’s "100% certain" rates will go down.

"Although I have not looked at Ontario very carefully, I am concerned that it still might be too market cavalier," Mr. Jaccard said.

And reforms done solely for ideological purposes carry a price, he said in the report. "Blind faith in markets is just as dangerous as blind faith in central planning. Any reform design that seeks benefits from the long-run cost efficiencies of competition must address the special characteristics of electricity."

California experienced blackouts and soaring prices a few years after it experienced deregulation. However, power prices have since fallen to expected levels. Alberta has gone from having one of the lowest electricity rates to one of the highest since it deregulated its market in January, 2000.

With deregulation, Mr. Jaccard said price fluctuations are certain. "Prices are going to go way up, and prices are going to go way down." To avoid this, he said deregulated markets should have the following:

– A reserve capacity market, in which producers are paid to keep little-used plants available to the market to ensure supply in times of high demand. "I would do it, even though I recognize that it carries some costs," he said.

– And the use of financial mechanisms – such as long-term fixed-price contracts – that would see large consumers, such as industrial users, cut back on demand during peak periods.

Neither of the mechanisms will be in place when Ontario opens its market, industry officials say. And the recommendations drew criticism from one industry observer.

"Those are both controversial proposals that have been championed by producer-side interests," said Tom Adams, executive director of Energy Probe, a power industry watchdog. "I remain skeptical that these measures are worth their high costs."

Mr. Adams was particularly critical of the reserve capacity proposal. "It certainly means higher electricity prices at times of low demand."

Ontario Electricity Coalition and Energy Probe.
St. Lawrence Centre Forum
February 26, 2002

The privatization, market pricing and restructuring of Ontario Hydro was the topic of a recent St. Lawrence Centre Forum.

Panelists: Tom Adams: Executive Director, Energy Probe, and formerly both an independent director of the Ontario Independent Electricity Market Operator and member of the Ontario Market Design Committee.

Howard Hampton: Ontario NDP Leader and Energy Critic, MPP for Kenora Rainy River.

Richard Perdue: member of the Minister of Energy’s Electricity Transition Committee, Director of Enterprise Canada’s energy division; former member of the Ontario Energy Board. Mr. Perdue is a former candidate for the Progressive Conservative Party.

John Wilson: Ontario Electricity Coalition, engineer and formerly both president of the Society of Energy Professionals and Hydro One board member.

Dana Flavelle
Toronto Star
March 11, 2002

Ontario’s electricity market has inched closer toward a competitive model with the sale of four previously government-owned hydro-electric generating plants to a private operator.

Ontario Power Generation announced yesterday it has sold four plants in northern Ontario to a division of Toronto-based Brascan Corp. for $340 million.

The sale reduces OPG’s dominance in the marketplace by just 2 per cent. Four other OPG plants remain on the auction block with uncertain prospects.

OPG chief executive Ron Osborne said the company has no plans to alter course.

"I have indicated parts of the process are moving more slowly than we would have liked," Osborne said in an interview yesterday. "We’re still in discussions with a number of interested parties. I can’t predict the outcome or the timing."

Some critics said yesterday it appears Brascan got a better deal than Ontario taxpayers. The proceeds of the sales of any OPG assets are to be used to pay down the $21 billion debt incurred by its predecessor, Ontario Hydro.

The plants, which generate an average of 0.7 terrawatts of power a month, are worth $50 million a year in sales to Brascan, a Sierra Club of Canada official estimated yesterday.

"The payback on their investment will be 7 years. That’s a good deal for Brascan," said John Bennett, director of atmosphere and energy for the Ottawa-based environmental lobby group.

Another sometime critic, however, disagreed. Energy Probe‘s Tom Adams said the price appears to be fair given current electricity rates.

Osborne defended the deal: "We think we got a full price here for these assets. Hopefully this signals other parties that we mean business. We’re not prepared to divest any other assets without getting a fair price."

Brascan was the obvious front-runner for the four plants on the Mississagi River, just east of Sault Ste. Marie, because the Toronto-based conglomerate owns one of the few independent power generating companies in the province and has run generating stations in that region for nearly 100 years.

"We’re delighted to have acquired the plants and think in conjunction with our existing operations we’re in good shape. We were also delighted to have been able to invest in Ontario," Harry Goldgut, chairman and chief executive of Brascan Power, said in an interview yesterday

Brascan, which also has mining, real estate and financial services interests, said the deal boosts its North American power generating capacity by 50 per cent to 1,500 megawatts. Its other facilities are in Quebec, Maine, British Columbia and Louisiana.

The Mississagi plants will be used to meet peak market demand in Ontario, Quebec and Michigan, Goldgut said. They’re not suitable as base load operations because their capacity is limited at certain times of the year by water availability, he said.

The plants employ about 24 people, who will all be offered jobs with the new owners.

The sale comes just weeks before the May 1 deadline for opening Ontario’s $10 billion annual electricity market to competition.

OPG controls about 75 per cent of the market, a figure it must reduce to 35 per cent within 10 years under the provincial deregulation scheme.

OPG’s only other major competitor currently is British Energy PLC, which owns about 15 per cent of the market through a long-term lease it signed with OPG to operate the Bruce nuclear facility.