MDS Nordion has enough enriched uranium for a bomb

Ian McLeod
Ottawa Citizen
June 9, 2002

Ottawa’s MDS Nordion is creating a tempting target for nuclear terrorists by unnecessarily stockpiling enough highly enriched uranium to build at least one nuclear bomb, says a respected U.S nuclear watchdog group.

The March Road company, the leading world supplier of radioisotopes for medical treatment and diagnosis, has 45.2 kilograms of highly enriched uranium – a two-year supply – waiting for the company’s long-delayed MAPLE nuclear reactors to go into service at Atomic Energy of Canada Ltd.’s Chalk River laboratories, northwest of Ottawa. A senior Nordion executive says about 22 kilograms of highly enriched uranium will likely be imported from the U.S. this year and added to the Chalk River stockpile, ending a temporary Nordion moratorium on uranium shipments because of the MAPLE startup delays. The company has an option to bring in another 22.6 kilograms next year under its U.S. export licence.

If so, Nordion and AECL will be sitting on a total of 90.4 kilograms of highly enriched uranium earmarked for the idle MAPLE isotope reactors by the time the export licence expires next year. Commercial operation of the primary MAPLE 1 reactor, delayed by technical problems for almost three years, won’t start until next spring or summer, at the earliest.

The situation is sending a post-Sept. 11 chill through nuclear and environmental policy groups in Canada and the U.S: experts say a nuclear bomb can be built with less than 25 kilograms of highly enriched uranium and a high-school knowledge of physics.

“There is already enough HEU for one or more nuclear bombs sitting in Eastern Ontario,” says Alan Kuperman, a senior policy analyst with the Nuclear Control Institute in Washington, D.C.

“This is a terrorist target just sitting there. It doesn’t mean (terrorists) could use the bomb in Ontario. But it certainly makes it a target of these sorts of groups, a very logical target, someone coming along and trying to steal this stuff. For better or worse, some (terrorists) who have come into the U.S. infiltrated into Canada first.

“The question is . . . how exactly is this material guarded and is it guarded as nuclear weapons material?”

Nordion says the institute is exaggerating the potential threat.

“It would be the first time that I’ve ever heard that Canada is a proliferation threat,” says Grant Malkoske, Nordion’s vice-president of engineering and technology.

He also suggests that any prolonged halt of Nordion’s supply of U.S. uranium would threaten the benefits nuclear medicine offers to millions of sick and suffering individuals. “If we didn’t have HEU here to produce medical isotopes, the world would be in difficult shape.”

The Nuclear Control Institute isn’t swayed. It recently renewed a formal request, first made last year, to the U.S. Nuclear Regulatory Commission to reject any new uranium requests from Nordion/AECL until commercial production actually begins at MAPLE.

“The beginning of production is a far off prospect and so there’s no reason to export any more in 2002,” says Mr. Kuperman.

The institute also is a leading advocate for getting all civilian research and isotope reactors in Canada, Europe and elsewhere to use non-weapons-grade uranium, or low-enriched uranium (LEU).

In exchange for a five-year licence to export U.S. highly enriched uranium, Nordion pledged to abide by a U.S. non-proliferation law, commonly called the Schumer Amendment, requiring it to pursue all reasonable measures to convert the MAPLE facilities to use low-enriched uranium. A condition of its licence is that it make annual reports to the commission – the latest was delivered to Washington last week – on its progress toward conversion to low-enriched uranium.

But Mr. Kuperman, along with Energy Probe, the Canadian nuclear watchdog group, accuse Nordion of dragging its feet on conversion to low-enriched uranium. The result, they say, is a dangerous proliferation of weapons-grade uranium in the Ottawa Valley.

“They want to use HEU in perpetuity,” says Mr. Kuperman.

Mr. Malkoske dismisses the charges. “What we’re trying to do is responsibly manage inventory.”

The MAPLE highly enriched uranium stored at Chalk River is Nordion’s attempt to meet its “obligation to the nuclear medicine community not to be short stocking medical isotopes,” he says. “The problem with HEU is that it is not a commodity type material, it’s very tightly controlled, very heavily regulated, (and) the procurement cycle is long and protracted. We just want to make sure there’s enough inventory in the pipeline.”

Whenever MAPLE 1 goes online, it will be used to irradiate the highly enriched uranium with neutrons, producing molybdenum-99, which decays into technetium-99m, the isotope most widely used in hospitals and clinics. (MAPLE 2 is to be used as a backup reactor.)

Nordion says technetium-99m and the company’s other radioisotopes are used in 50,000 medical tests around the world each day to diagnose cancer and heart disease, as well as to detect abnormalities in the brain, heart, lungs, liver, thyroid, kidneys and bone.

“The material itself is contained in AECL’s licensed facility, a Class 1 facility, it has specific security requirements, endorsed by the Canadian Nuclear Safety Commission. In terms of a terrorist threat, I don’t think so.”

The Canadian Nuclear Safety Commission and the U.S. Nuclear Regulatory Commission said this week that Nordion is operating within government regulations.

“I get a little bit anxious when people call it weapons-grade,” says Mr. Malkoske. “For me, it’s isotope-production grade. You can use it for other purposes. It’s like gasoline, you can use it to run your car or you can use it to light a fire. If you use it for what it’s intended for, it’s not a concern.”

Norman Rubin, Energy Probe’s director of nuclear research, doesn’t buy that argument. “Jet fuel was used to bring down the World Trade Center. We’re all a little smarter, maybe a lot smarter, than we were a year ago and it’s time that Chalk River got as smart as Washington, D.C.,” he says.

“We are presenting an attractive target to malicious humans who’d love to get their hands on nuclear weapons material.

“Not only are they playing with fire, in the sense that everybody but them is more concerned about theft, diversion, malice, terrorism, than we were a year ago, but . . . the U.S. has taken a principled stance to stop spreading nuclear-weapons useable material around in the guise of civilian activity and their clients have agreed (to convert to low-enriched uranium). I believe the only exception, (is) the otherwise nice country called Canada.”

But Mr. Malkoske said Nordion never agreed to convert to low-enriched uranium at any cost.

“It is not written in stone,” he says. “Technically, it seems feasible to me, but what’s it going to cost to do this? Everytime you add costs you pass that on to the health-care community, you increase the cost of nuclear medicine.

“What we said we would do . . . is do a technical and economic feasibility (study) and if it was economically feasible then we would convert. We didn’t say we were going to convert at any cost. That could kill our business.”

If conversion to low-enriched uranium does go ahead, he estimated it wouldn’t be until 2007, at the earliest, meaning Nordion and AECL may have to continue importing highly enriched uranium from the U.S. if MAPLE 1 goes into production next year.

Mr. Rubin says Canadians “should be concerned and outraged.”

“Canada, a nation of peace-loving people, is behaving in an outrageous manner, thwarting the attempts of our neighbours to the south to limit the spread of nuclear-weapons usable material.

“The U.S. should make it very clear that no more HEU is coming to Canada. If that means Nordion has to convert quickly rather than slowly, then that’s what they have to do. If it means that they’re uncompetitive . . . then that’s the right answer.”

Posted in Nuclear Plant Security | Leave a comment

Unfettered electricity markets fuel cynics in Alberta

Lily Nguyen

June 6, 2002

CALGARY — Alberta businessman John Davies has spent a year and a half on the deregulation roller coaster, and he’s now tired of the ride.

Mr. Davies, who owns Lethbridge Ironworks Co., blames the deregulation of Alberta’s electricity markets for power costs soaring so high that he considered moving his 104-year-old family business out of the province.

“Our monthly power bill is up about 60 per cent from where it was before deregulation,” said Mr. Davies, who said he will stay in the province for now. “Seventy-two thousand dollars would be a typical month for us now. Before, it would’ve been in the order of $45,000 to $50,000.”

Lethbridge Ironworks is an iron foundry.

“The benefits of deregulation have not materialized,” he said, echoing the sentiments of many who have experienced skyrocketing power prices and market chaos in Alberta and California, two jurisdictions that recently opened their power industries to competition.

But despite the increasing cynicism about deregulation, experts argue that Alberta’s experience has not been a disaster as it was in California.

After rampant blackouts and multibillion-dollar bankruptcies, that whole system needed to be redesigned.

In fact, deregulation, completed on Jan. 1, 2001, is delivering many intended benefits, including greater supply, increased business and trade opportunities, and a more efficient, environmentally friendly industry, observers say.

“We see new plants being built, plants being built more efficiently and greater care taken on how we operate those plants,” said Joseph Doucet, a University of Alberta business professor and deregulation expert.

Wholesale power prices – the cost of large power blocks bought from the electricity generators – have fallen dramatically, he said.

Unfortunately, the benefits of lower prices have not yet trickled down to end users such as Mr. Davies and most household customers. For small businesses and residential customers, that’s largely because various temporary measures taken by Ralph Klein’s Progressive Conservative government to shield consumers from price shocks continue to muddy the waters. In addition, many mid-sized businesses such as Lethbridge Ironworks entered into contracts for power prices above current spot market levels.

“There’s a tremendous number of companies that will be unhappy with deregulation for five to 10 years,” Mr. Davies said. “They signed long-term contracts.”

Nancy Janes, a spokeswoman for the Alberta Power Pool, the central power exchange, confirmed that wholesale prices have fallen.

The province’s total power capacity – the amount that can be produced if all power plants are running and feeding their power into the grid – rose by 700 megawatts or 7 per cent last year, she said. That’s enough to power a city twice the size of Calgary.

Another 1,248 megawatts are planned for this year, and a total of 5,000 megawatts are expected over the next five years, she added.

As a result of increasing supply, wholesale power prices have eased dramatically. In 2000, wholesale electricity averaged $133.22 per megawatt-hour. In 2001, after deregulation was completed, it averaged $71.29. So far this year, it has averaged $37.32.

Dan Macnamara, executive director of the Industrial Consumers and Cogenerators Association of Alberta and an outspoken critic of deregulation, acknowledged that Alberta’s system is improving.

“We are progressing,” said Mr. Macnamara, whose membership represents the province’s large industrial users, which make up about half of the province’s electricity demand. However, he added that the retail electricity market needs more players to be competitive.

Tom Adams of Toronto-based Energy Probe said deregulation also should be credited for Alberta’s power supply diversifying into a cleaner mix of fuels, away from its reliance on coal, which produces high greenhouse gas emissions.

“Alberta’s experience has helped the province move to a much less coal-dependent power system,” said Mr. Adams, executive director of the environmental and consumer advocacy group. “That counts for something.”

Mr. Adams said coal-fired plants require long time horizons of about five years and huge capital outlays to build, and therefore are suitable for regulated systems where producers can count on getting their costs back plus a fixed return. Under a deregulated system, producers are less willing to lay out capital on long time frames, and so tend to opt for gas-fired plants, which cost less, take half the time to build and produce far less emissions.

The Alberta Power Pool’s Ms. Janes said that, as of the end of 2001, gas-fired power made up 4,000 megawatts of electrical capacity, up from 2,500 megawatts at the end of 2000. Coal-fired power increased only marginally to 5,770 megawatts at the end of 2001 from 5,650 at the end of 2000. Less significant sources include hydroelectric power and wind power.

Mr. Adams said the diversified energy mix could serve Alberta well if Ottawa ever implements carbon taxes to reduce emissions under a plan to meet targets set out in the Kyoto Protocol.

Fair enough, said Lethbridge Ironworks owner Mr. Davies, but that means little to smaller customers who built their businesses based on the consistently low power prices of the past.

“There’s about 10 winners in Alberta and three million losers.”

Jim Wachowich, a consumer advocate and lawyer for the Consumers Coalition of Alberta, said that not only are consumers paying higher prices now than before deregulation, they must grapple with greater complexities on a commodity they used to take for granted.

Mr. Wachowich said the province’s various measures to ease the shock of power prices have made for a confusing power bill, full of line items detailing extra charges.

“Here consumers are being told it’s a competitive marketplace and you can make choices, but they can’t even understand the status quo services because they’re confused by the bill,” he said.

In 2001, an election year, the Tories spent a total of $2.3-billion on a $40-a-month rebate on residential power bills, plua a per-unit rebate for small businesses. The government also forced utilities to defer until 2002 to 2004 some of the rate increases consumers would have paid in 2001.

At Enmax Corp., Calgary’s electrical utility, spokesman Tony McCallum said the average residential power bill charged by the company is $76 a month this year, compared with $67 in 2001. But by factoring out the rebates and other measures, the average monthly bill this year would be $72 compared with $107 in 2001, he said.

It’s still higher than the $43 a month that consumers paid before deregulation, but the trend is clearly downward, he said.

And, as Mr. Doucet points out, power prices probably would have climbed even in a regulated system because the price of natural gas, an input, had soared. Power prices also were indirectly driven by California, because the power imports that were usually available from British Columbia to ease tight supply in Alberta were headed down the U.S. West Coast instead.

But for Mr. Davies, the fact that the Alberta power market appears to have avoided a meltdown similar to California’s and that it is on the path to recovery brings little comfort. “The fact that we’re better than California doesn’t mean we’re great; it just means we’re better than them. You would be a success story if you had both your legs chopped off and the other guy’s killed.”

 

Posted in Alberta Power Industry | Leave a comment

Gas war heats up

Joel Bernard/Tom Adams
National Post
May 27, 2002

Letters to the Editor:

Re: East Coast Gas Wars

 

New Brunswick’s application to the National Energy Board does not suggest “how to cut off gas shipments to the United States,” as the article East Coast Gas Wars (May 14) states. It recognizes that a certain volume of natural gas is needed to make the Maritimes and Northeast Pipeline viable. It is well known that New Brunswick supports that pipeline; the only purpose of the application is to ensure that Atlantic Canadians have access to new gas supplies at the same price that the Sable producers are getting from U.S. purchasers.

The current rules of the NEB contain a loophole allowing it to approve exports for natural gas for terms less than two years without any other Canadians knowing about it. When those rules were put in place in 1991, over 80% of the gas exports from Canada were for terms longer than two years, and so could not take advantage of these short-term export orders. Longer exports need an NEB licence and Canadians receive public notice and an opportunity to buy that gas. But today, about 80% of all gas exports leave Canada under short-term orders, with no one in Canada except the NEB and the exporters knowing about them.

Without new discoveries, current producible reserves will last only about 12 years. The Deep Panuke (EnCana) reserves, scheduled to come on stream in 2005, will last 10 or 11 years at forecast flow levels. New Brunswick is concerned that the supplies may prove finite all too soon.

New Brunswick is simply asking the NEB to ensure that the public get notice of any proposed short-term export order for Scotian offshore gas, so that anyone in the Maritimes who wants it can match the U.S. price. Under New Brunswick’s proposal, Canadians would have an equal opportunity to acquire natural gas produced from Canadian resources whose developments they themselves helped finance through Petroleum Incentive Program grants in the 1980s.

I might also note that there are no legal obstacles in New Brunswick to cogeneration; in fact, gas is already in use for such projects there.

Again, New Brunswick’s application only seeks to give Canadians equal access to a Canadian resource, Scotian offshore natural gas, rather than having to wait in a queue behind American users.

Joel Bernard, MLA (Nepisiguit)
Legislative Assembly, Fredericton

Tom Adams responds:

What I said was that “New Brunswick demands that the region’s gas exports be subject to regulatory controls, with the National Energy Board in its wisdom deciding how much gas should be turned back at the U.S. border, for the benefit of Eastern Canadians.”

Tying up gas exports in red tape, as New Brunswick’s government wants, will ensure that only a small portion of the gas reserves in the Eastern off-shore get developed.

New Englanders are successfully using Eastern Canadian gas to power their economy, mostly by converting it into electricity through advanced processes that are also extremely clean environmentally. Meanwhile in New Brunswick, opportunities for this technologically advanced, competitive path to economic prosperity – like at the Irving Oil refinery in Saint John – languish. Why? In large part because NB Power, the province’s debt-laden Crown monopoly, has the legal right to block any power generator from being constructed.

Because the gas is not shipped as far, consumers in Nova Scotia and New Brunswick already get gas cheaper than consumers in New England. With sensible policies – starting with the breakup of the province’s electricity monopoly – New Brunswick could begin to share in the prosperity south of the border, instead of attempting to beggar its neighbour.

 

Posted in New Brunswick Power | Leave a comment

Nuclear plant delays expected to jolt pricing

Paul Vieira
National Post
May 27, 2002

The delay in Ontario Power Generation Inc.’s efforts to bring its troubled Pickering A nuclear plant back into production could have an impact on the supply, reliability and price of hydro in the province, industry watchers say.

“The delay in returning Pickering A to service, combined with the [Hydro One uncertainty] and slowdown in private-sector investment, is substantially increasing the risk of big price swings and big price spikes,” said Tom Adams, executive director of Energy Probe. “When you combine all these factors together, the consequence for Ontario’s power outlook is profoundly unfavourable.”

The uncertainty surrounding Pickering A, Mr. Adams and others say, has forced electricity producers to rethink their investment in Ontario, largely because they can’t get a grip on where electricity prices are headed.

At full capacity, the nuclear plant, located east of Toronto, can produce 2,000 megawatts of power – or enough for a city of two million.

“Pickering A has certainly been a factor in evaluating where prices will be,” said Duane Cramer, vice-president of development for Sithe Energies Inc., a New York-based power utility that has two projects under way in suburban Toronto. “We see Pickering A more as a spectre than an operating unit – and as long as it is out there, there will be a depressing view on the power price.”

Prices have been stable since Ontario’s $10-billion market opened its doors to competition on May 1. Under the new regime, utilities can build generation plants in the province and sell the power into the market. That, in turn, is supposed to create competitive electricity pricing. However, two key elements in Ontario’s reforms remain unresolved.

First, a court ruling blocked the privatization of Hydro One, the Crown-owned transmitter. The sale through an initial public offering is in question as the province re-evaluates the strategy.

But more recently, OPG, the Crown-owned generator, announced another delay in the startup of its Pickering A nuclear generator.

Pickering A was shut down in December, 1997, due to safety concerns. OPG had planned to get the first of four units at Pickering A back into service in early 2001, and forecasts developed by Ontario’s Independent Electricity Market Operator – which runs the province’s wholesale power market – assumed that when it suggested the province had an ample supply of power.

But structural and engineering problems have delayed Pickering A’s restart – with the latest setting back generation until late this year or early 2003. The cost has ballooned as well, from an original estimate of $800-million to the most recent estimate of up to $2.2-billion.

John Earl, a spokesman for OPG, said getting Pickering started is in the company’s, and public’s, best interest. “OPG, as commercial venture, is returning Pickering A to service based on what we believe to be the best advantage for the customer and for ourselves as a corporation,” he said.

Mr. Adams said Pickering is hanging over the industry like a dark cloud. “What the Pickering restart has done is to scare away a tremendous amount of investment in alternative generation,” he said. “And now the absence of Pickering – since its driven away alternatives to Pickering – leaves Ontario with a big hole in its power system.”

In an October, 2000, hearing before the Ontario Energy Board, an executive with Union Gas Ltd. said forecasts for natural gas demand indicated a downward turn because utilities looking to build gas-fired plants had scrapped or delayed plans because of the Pickering A restart. “[If] the Pickering plant comes back into play, the marginal cost of electricity coming out of that facility will make it very difficult for a startup operation to be able to compete with [OPG],” said Rick Birmingham, Union Gas’s vice-president of finance and business development.

While a number of companies, such as Sithe and Montreal’s Boralex Inc., say they have plans to build generation facilities in Ontario, “they are no where to be seen and way behind schedule,” Mr. Adams added.

But one industry insider disagreed, saying utilities are cautious because of soft electricity prices. “Low prices are fine for consumers and the government, but not for generators,” the insider said. “The prices are just too low. It makes the game a little more confusing.”

Posted in Nuclear Economics | Tagged | Leave a comment

East coast gas wars

Tom Adams
National Post
May 14, 2002

 

Open borders and deregulation are on the agenda this morning at an energy conference in Saint John, where the New Brunswick government hosts the New England governors and the Eastern premiers in a long awaited free trade initiative.

The New England governors might have to wait longer.

New Brunswick’s government has just decided to add a new item to the top of the agenda – how to cut off gas shipments to the United States.

When New Brunswick announced the conference in February, it was to address “free market competition, borderless energy flows, security of supply and environmental implications, and opportunities including infrastructure development and development of secondary industries.” Premier Bernard Lord then talked about turning New Brunswick into an “energy nucleus” for the Atlantic seaboard.

On the eve of the conference, however, the New Brunswick government turned protectionist. The output from the rapidly expanding Sable Island gas field off the coast of Nova Scotia, which is piped through New Brunswick, is largely destined for New England. Why should New England get this Canadian gas instead of us, reasons Mr. Lord?

To get an answer he’d like, Mr. Lord’s government has asked the National Energy Board to repeal its market-based gas export rules when it comes to Atlantic Canada. Instead, New Brunswick demands that the region’s gas exports be subject to regulatory controls, with the NEB in its wisdom deciding how much gas should be turned back at the U.S. border, for the benefit of Eastern Canadians. In what’s shaping up to be a free-for-all, a total of 42 governments, energy companies, and citizens’ organizations have applied to the National Energy Board for intervener status in the public hearings that will begin in Fredericton July 15.

The position of New Brunswick, as explained by its Minister of Natural Resources and Energy, Jeannot Volpé, is that “Rules to favour exports are not in [Canada’s] best interests,” and that rules to curtail exports are “not a subsidy.” The Quebec government and two pipeline companies it partly owns, Gaz Métropolitain and Enbridge Inc., have joined New Brunswick, wrapping themselves in the Canadian flag. Quebec Inc. has been trying for decades to find a rationale, or enough subsidies, to justify building a pipeline from the New Brunswick border to Quebec City. Forcing Sable Gas to flow west instead of south provides both a rationale and part of the subsidy. Eastern Canadian gas consumers would also provide a subsidy through higher rates.

Behind New Brunswick’s machinations lie a desire to boost its economy with a fresh infusion of natural gas. Yet its heavy-handed approach has not worked well before. Since Sable Island gas arrived in New Brunswick in 1999, the province’s performance has been lacklustre. Regulatory rules imposed by the provincial government prevented the local New Brunswick distributor from selling gas to consumers – instead of hooking up several thousand new customers in its first year of operation, as planned, the distributor managed only a few hundred. And legal prohibitions on cogeneration – the simultaneous production of heat and power that is booming elsewhere in the world – have stunted its development in New Brunswick. In contrast, the arrival of Sable gas in New England fueled a construction boom in cogeneration, even though Sable gas costs more in New England than in New Brunswick.

Popular sentiment in New Brunswick blames the Americans for the weak sales of gas in New Brunswick. An opinion column in the Fredericton Daily Gleaner complained, “In short, Canadian gas, primed by many millions of federal tax dollars, is bypassing New Brunswick, and it’s a hard pill to swallow.” The truth might be harder still for short-sighted nationalists to swallow: Without the demand for gas from New England consumers, Sable gas would never have been developed, and no Sable gas would be available in New Brunswick.

Atlantic Canada’s offshore gas reserves – off Sable Island and nearby locations – appear to be very large. A recent large find called Deep Panuke is scheduled to come on line in 2005 and the owner – EnCana Corp. (formerly PanCanadian) – is beating the bushes to find buyers. To carry this additional flow, the pipeline now carrying Sable gas through the Maritimes and to the U.S. Northeast has asked for permission to increase its capacity by two-thirds. A National Energy Board decision that turns back Canadian gas at the U.S. border would signal EnCana and others to do their future exploration elsewhere.

Ironically, more than Eastern Canada’s economy would suffer. The power utilities in the U.S. Northeast have been heavy polluters of the Maritimes, leading to pressure on them from environmentalists and many Canadian governments, including New Brunswick, to cut smog and mercury emissions from their coal- and oil-fired power plants. The arrival of Sable Island gas allowed New England to switch to high efficiency gas-fired industrial cogeneration – fully half of the U.S. Sable gas imports go to cogeneration – and to new natural gas networks, providing Canada with cleaner air. If New Brunswick’s protectionism prevails and offshore gas development slows or stops altogether, New England’s coal- and oil-fired power production will persist, and eastern Canada’s gas consumers will bear the cost of any uneconomic pipelines that then get built.

Posted in New Brunswick Power | Leave a comment

NB Power’s Proposed Point Lepreau Retubing

Tom Adams, Executive Director

May 7, 2002

Review of Financial Fitness, Institutional Certainty, and Investment Risk

Submitted to
New Brunswick Public Utilities Board
Concerning a Proposal to Refurbish the Point Lepreau Nuclear Generating Station

Summary

New Brunswick’s electricity system is financially unfit to undertake the proposed Point Lepreau retubing effort. New Brunswick’s electricity system faces a combination of negative factors. NB Power’s debt is unfavorable and its operating costs, already the highest of the Canadian utilities for which comparable data are available, are trending to become more unfavorable. These factors combined with persistent reported negative net income, unreported costs, and slow progress in debt reduction make NB Power the weakest utility in Canada in financial terms. The utility suffers from a lack of policy direction and only has an acting CEO yet is pursuing an aggressive capital spending strategy. NB Power is on track to have the highest relative debt in Canada, a factor that is likely to increase rates. If current trends continue, New Brunswick’s power system is likely to face more significant financial challenges in future years than those it now faces. Should current trends continue, a significant injection of capital from some level of government may be required to allow the power system to remain functional.

NB Power’s investment strategy is risky.

Some alternative low-carbon energy alternatives to nuclear investments are suggested and some similarities between NB Power’s application and Ontario’s recent experience with monopoly utility central are identified.

NB Power’s Unsustainable Liabilities and High Operating Cost Exposure in Context

New Brunswick’s electricity debt is already excessive and will increase substantially under its proposed capital program.

Utility liabilities, including debt and other obligations, contribute to current and future rates. Excessive debt levels can reduce a utility’s financial flexibility. Operating costs contribute to current rates. Excessive operating costs can also reduce a utility’s financial flexibility.

1


It is financially appropriate for utilities providing services that are to some extent necessarily capital intensive to incur debt. One justification for utility debt is to acquire assets that have low operating costs. A common example is hydro-electric generating investments. Although their capital costs are high, their running costs are typically relatively low.

Excess utility liabilities, particularly when combined with high operating costs, are damaging to the public interest. Relative to all other utilities in Canada, NB Power has put itself in a double jeopardy situation of high liabilities and also high operating costs.

Several methods can be used to calculate utility debt. The method normally relied upon in Canada, particularly by Crown utilities, in their financial reports, is long-term debt at face value less any long-term debt due within one year. For the purposes of this analysis, a more expansive definition of debt is used, drawn from the debt definition used by NB Power to calculate its debt/equity ratio. Debt here is defined as long-term debt plus short-term debt plus spent fuel management and decommissioning minus cash and short-term investments minus sinking fund investments.

By this measure, NB Power’s liabilities sum to $3.149 billion for 2001 and $3.160 billion for 2000 and $3.667 billion for 1994.

A highly levered utility with no major capital projects underway, like NB Power, would normally be expected to generate a significant amount of cash to pay down debt. Instead, NB Power’s debt is dropping only slightly. Debt declined $11 million in 2001 over 2000. The annual rate of decline was $74 million or 2% over the last seven years. At the average rate of debt decline demonstrated over the last seven years, NB Power’s existing assets would have to continue performing at the present rate of profitability without capital investment for over 50 years to pay off the debts incurred acquiring those assets. Many of NB Power’s main generation assets will reach the end of their economic life in much less than 50 years.1

NB Power’s fuel mix, a key factor influencing the structure of its costs, both debt and operating costs, is similar only to Ontario’s.

The former Ontario Hydro’s total liabilities were calculated by the Ontario government at $38.5 billion as of March 31, 1999, at the point of Ontario Hydro’s dissolution. The method of calculating the total liabilities summed the value of the utility’s debts using a fair market value method, the present value of the nuclear waste using a method similar to that employed by NB Power in its accounts, and an estimated market value for the net losses from long-term power purchase contracts.


1 The status of NB Power’s largest hydro-electric unit, the 672 MW Mactaquac dam on the Saint John River, is relevant to NB Power’s rate of paying off its assets. Mactaquac’s concrete is subject to alkali aggregate reaction, a chemical process causing the concrete to swell and become stressed. NB Power has recently received an expert suggesting that the station life will have to be substantially shortened. The current life expectancy extends until 2038 but the plant may become unsuitable for operations as soon as 2015.

2


Ontario’s high electricity debt was one of the major factors behind the provincial government’s 1997 decision to restructure Ontario’s electricity economy. New Brunswick’s electricity debt is much greater in relative terms than Ontario’s. New Brunswick’s electricity debt relative to the size of the provincial economy is almost twice that of Ontario – NB Power’s debt equals 16% of the provincial economy whereas the old Ontario Hydro debt (defined more broadly than NB Power’s debt) equals 9% of the provincial economy. Electricity debt per worker in New Brunswick is $9,200 whereas in Ontario it is $6,400.2

One indicator of a utility’s ability to bear debt is its net income. Not only is NB Power is the only major utility in Canada in the last several years to generate negative net income except for Ontario Hydro, NB Power’s has persistently generated negative net income. Excluding transfers from internal accounts, the only year in the last 7 that NB Power experienced positive net income was in fiscal 2000. Over this 7 year period, NB Power has been issuing business plans forecasting dramatic turnarounds in the net income performance. For example, in the 1996 Business Plan NB Power forecast that its net income would improve steadily so that by fiscal 2001, net income would be $75.9 million. The actual for fiscal 2001 was a loss of $12 million. Further documentation of NB Power’s consistent overestimate of future net income is available at NB Power’s reply to Energy Probe’s interrogatory #6.

If NB Power proceeds with its three major capital projects, and assuming no cost overruns, no change in NB Power’s current rate of debt reduction from internal cash flow of $74 million per year (the average rate over the last 5 years), a continuation in the decline of population in New Brunswick at the current rate of 1.2% per 5 years and no change in the employment rate, New Brunswick’s electricity debt per worker will be the highest in Canada by 2007 – over $13,000 per worker.


2 NB’s employed population in 2001 is 342,000, therefore debt per worker is $9,200. Ontario’s employed population in 2001 was 5,997,000, resulting in a per worker debt of $6,400. Ontario’s GDP in 2000 was $430 billion, resulting in an electricity debt of 9% of the GDP. NB’s GDP in 2000 was $19.7 billion.

3


Public Electricity Debts
Year Long-
term
debt
Current
Liabilities
Waste Current
Assets
Sinking
Funds
Total per 2001
Worker
per 2000
GDP
Saskpower 2000 1571 219 326 1464 $3,074.34 4.37%
BC hydro 2001 7633 2140 1307 1148 7318 $3,795.64 5.74%
Manitoba 2001 6020 933 540 1149 5264 $9,389.94 15.57%
Hydro Quebec 2000 34887 8532 87 3103 40403 $11,469.00 18.12%

NB Power’s Running Cost is Uncompetitive

Another key financial parameter for utilities is the variable and semi-variable cost of operations. If a utility had no debt, no depreciation of assets, and paid no taxes, its rates would have to recover only its operating costs and fuel costs.

In its February 1996 study of public electric utilities in Canada, the Dominion Bond Rating Service (DBRS) found that NB Power had the highest variable and semi-variable cost structure of the utilities studied. It found that NB Power’s variable and semi-variable costs of fuel and labor are “so high at 3.23 cents per kWh that they exceed Hydro-Québec’s final sales prices to large industrial customers (about 2.75 cents per kWh).”3 The gap between NB Power’s operating costs and Hydro Quebec’s industrial rate that drew DBRS’s attention was 17%. Since the DBRS study was published, the gap has widened. NB Power’s operating cost – 4.3 cents/kWh – is now 22% higher than Hydro Quebec’s average industrial rate, which is 3.5 cents/kWh.4

NB Power has the highest running cost of any comparable utility in Canada. Utilities that rely relatively more on hydro-electric generation and less on coal and nuclear generation normally enjoy lower operating and fuels costs. Nova Scotia Power with about half the hydro-electric market share of NB Power had operating costs in 2000 of 4.0 cents/kWh.5 Saskpower, which has about the same amount of hydro-electric generation and much greater coal reliance than NB Power, had operating costs in 2000 of 3.4 cent/kWh. For HQ in 2000, the comparable figure is 0.24 cents/kWh6


3 Dominion Bond Rating Service, “The public electric utilities in Canada: An emerging problem for provincial credit ratings,” February 1996.
4 ($309 million for operating cost + purchase power $100 million + fuel $401 million) on 18.8 TWh of sales = 4.3 cents/kWh.
5($157 million for O&M + $273.9 million for fuel and purchased power) on 10.7 TWh of sales = 4.0 cents/kWh.
6($2.135 billion for operations + $2.408 billion for electricity and fuel) on 190 TWh = 0.24 cents/kWh.

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NB Power’s High-risk Investment Strategy

Not withstanding its weak financial condition, NB Power is pursuing an aggressive expansion strategy.

NB Power has received approval from the Public Utilities Board for its planned $747-million refurbishment of 1000 MW Coleson Cove generating station. The plan requires converting Coleson Cove from an oil-burning unit into an station burning Orimulsion – a bitumen-water slurry marketed by the Venezuelan state oil company. The plan is part of the utility’s efforts to increase exports and provide back up for Point Lepreau nuclear station.

NB Power is seeking permission from the provincial Public Utilities Board (PUB) and the government to invest an amount it currently estimates at $845 million to extend the life expectancy of the Point Lepreau reactor through retubing and other rehabilitation programs.

Experience with other Candu reactors shows that such refits are commercially risky. From 1983-1989, Ontario Hydro attempted a refit of similar scope on four Pickering reactors. Between 1993 and 1997, Ontario Hydro recognized that the refit had been a failure, wrote off the debts it had accumulated to pay for the refit and the other cost reflected in the net value of the station, and put the four reactors into an extended lay-up condition. A large element of Ontario Hydro’s Pickering refit write-offs was debt owing from Atomic Energy of Canada Limited (AECL), the federal nuclear company. AECL and Ontario Hydro had a risk-sharing partnership in Pickering units 1 and 2.

Contrary to many public statement by Ontario Hydro and other nuclear interest groups, the closure of Pickering A was driven in part by a regulatory safety decision. Ontario Hydro had failed to upgrade the obsolete single fast shutdown system on each of the four reactors by the December 31, 1997 deadline imposed by the Atomic Energy Control Board and therefore was forced to close the reactors.

AECL has a risk sharing partnership with NB Power in the Point Lepreau project. This partnership leaves NB Power with substantial risk. One potential risk is that NB Power is relying on AECL’s continued solvency. AECL’s continuing funding from the federal government and the methods for dealing with its unfunded nuclear waste liabilities are currently matters of public discussion and uncertainty. Even if the guarantee is enforceable, the terms of the guarantees leave NB Power with significant financial exposure. AECL has agreed to guarantee that the Point Lepreau station will operate at 80% capacity factor after retubing, however, NB Power’s cost/benefit analysis for the retubing investment assumes the unit will operate at 89%. Another risk is that under the terms of the “Memorandum of Agreement on Plant Performance Agreement”, after the plant generates as much power as is forecast for approximately 6 years following retubing, if the plant shuts down permanently AECL is not required to compensate NB Power for any of its losses. (NBP Interrogatory reply PUB #8) In addition, NB Power has no contingencies if the retubing outage is extended (NBP Interrogatory reply JDI #11)

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The failed Pickering A refit was one of the main causes of Ontario Hydro’s financial collapse in 1997. Failure of the Point Lepreau refit would have a more severe impact on New Brunswick than the impact Pickering A has had on Ontario because of Pickering A’s smaller relative size and Ontario’s lower relative electricity debt.

Institutional Uncertainty about New Brunswick’s Electricity Future

NB Power is pursuing it major capital expansion initiatives in the face of uncertainty over the future institutional arrangements for New Brunswick’s power system.

The government released an Energy Policy in January 2001. The Energy Policy sets out a 10-year phase-in for electricity market reforms with the objective of enhancing competition and opportunities for cross-border trade. According to the Energy Policy, the government intends to introduce amendments to the Electric Power Act to allow for private, non-utility power generation consistent with the Energy Policy. Amendments to the Public Utilities Act will also be introduced to amend the Public Utilities Board’s capabilities to regulate in a more open, competitive marketplace. The government has announced that it will issue its opinions on the future ownership of NB Power sometime during 2002. The Energy Policy anticipates the creation of exit fees to recover stranded cost from consumers seeking competitive alternatives to NB Power.

The investment required to return Point Lepreau to service is much greater than that required to return other nuclear facilities to service. Point Lepreau’s refit is forecast to cost more than $1300/KW, Pickering A (for its second major refit) is forecast to cost $728/KW and Bruce 3 and 4 is forecast to cost $227/KW. These comparisons alone suggest that NB Power is risking creating fresh stranded cost just before a new electricity market begins.

NB Power is currently operating with only an acting CEO, a factor that further reduces the potential for a successful major project.

NB Power Nuclear Accounting Issues

NB Power’s regulatory filings at the hearing into the refit of the Point Lepreau station reveal a pattern of overestimating reactor component lives, under-collection of funds for reactor dismantlement and radioactive waste disposal, and deferral of nuclear cost recognition far into the future. The company’s preferred solution is to defer all the costs decades further into the future.

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The testimony reveals an undisclosed liability of $120 million. In 1999, faced with more rapid aging of reactor core components than had been expected at Point Lepreau, NB Power reduced the life expectancy of the unit by six years. Shortening the recovery period for the money sunk in the reactor resulted in a $450-million charge.

Although NB Power’s accounts starting in 1999 acknowledge the cost of the reduced life expectancy, the utility has not made a corresponding increased charge by recognizing the liabilities associated with cleaning up and dismantling, or decommissioning, the station after its use. Instead, the utility continued to report decommissioning liabilities as if the station will continue to operate at a high level of production until the end of the original, longer life expectancy, which extended out to 2014.

NB Power’s annual report notes that the assumptions underlying decommissioning costs are different than those used for the recovery of money sunk in the reactor. However, the impact of this discrepancy was not revealed until NB Power filed its testimony before Public Utilities Board on 2002 February 25. The undisclosed liability of $120 million translates into a 3 per cent rate increase if all other costs and assumptions remain the same.1

The Report of the Environmental Assessment Panel on the Second Nuclear Reactor, Point Lepreau, New Brunswick (1985), recommended that “The annual decommissioning levy be scaled so that contributions are higher during the first years of operation.” 7 NB Power has not followed this principle in the funding of decommissioning and radioactive waste disposal at Point Lepreau to date.

Undisclosed decommissioning costs are not the only nuclear accounting concern. The $450-million writedown in 1999 resulted from NB Power taking the most optimistic interpretation of an external technical review of Point Lepreau’s accelerated decay. The utility now claims that the life expectancy of the station must be cut by another two years, to 2006, consistent with the most pessimistic scenario set out back in 1999. The utility is also suggesting that the end may come as early as 2005, an event that would increase the potential writedown significantly.

If the option of investing in a refit for Point Lepreau is turned down, the financial impact of recovering the money already sunk in the station – based on the most optimistic estimate for the shorter remaining service life, combined with the need to recover the undisclosed decommissioning costs – would result in a rate impact of 13 per cent.8


7 The Report of the Environmental Assessment Panel on the Second Nuclear Reactor, Point Lepreau, New Brunswick (1985), Recommendation 38 (a).
8 For the period 2002-2006, subtracting the amortization and decommissioning expectations for the retubing scenario [$758 million] from the non-retubing scenario [$1183 million] equals $425 million. Assume that approximately $50 million in ‘new’ amortization and decommissioning costs are recovered in this period under the retubing scenario. Therefore, the incremental amortization and decommissioning costs are estimated at $475, equal to an annual impact of $147 – 13 per cent of rates.

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Even if NB Power had no other undisclosed and underestimated costs, the utility would be facing a severe financial crunch due to under-recognized nuclear waste disposal and decommissioning costs. The utility estimates its costs for waste disposal and decommissioning at $843 million in 2001dollars. Although Point Lepreau is more than three quarters through its service life and its best production years are behind it, NB Power only recognizes $221 million in provisions for these future costs. Recovering its forecasted exposure to nuclear waste disposal and decommissioning costs may drive rates up substantially although the amount will depend on the treatment of interest cost.

Nuclear waste disposal and decommissioning costs may rise further. NB Power’s estimated decommissioning cost is below the most optimistic estimate used by the nuclear regulator in the United States. NB Power estimates $454 million, whereas the U.S. Nuclear Regulatory Commission’s estimates range from $475 million to $715 million for pressurized water reactors, which are smaller and less radioactive than CANDUs.9

Canada’s nuclear safety regulator has grown increasingly uncomfortable in recent years with the nuclear utilities’ historic waste-funding practices. Canada’s nuclear utilities have not set aside money providing for these so-called “back-end” costs in funded accounts at arm’s length from the utility and its other financial obligations, as could be done through segregated trust accounts. Instead, the money collected for back-end costs has been used by utilities to invest in the general equity of the firm.

NB Power’s severe debt crisis directly threatens the back-end provisions invested in the general equity of the firm because its equity, if measured in market terms, is probably negative. Armed with recently upgraded legal powers, the federal regulator is moving toward tighter, U.S.-style financial standards with full funding of back-end costs. Ontario’s decision to start funding back-end costs for nuclear reactors is one of the factors driving up electricity rates there.

If the Point Lepreau refit is approved and the reactor works as efficiently as the utility forecasts, the buildup of undisclosed, underestimated and under-recognized costs can be stretched over the next 30 years. If, as was the experience at Pickering A, the refit proceeds but fails to achieve its cost and production targets, the financial impact could be severe.

Alternative Greenhouse Control Strategies

Nuclear generation has the advantage of not releasing significant amounts of conventional air pollutants, including greenhouse gases. Valuing this advantage for the purposes of investment planning is inherently subjective. The provincial government has no official position on climate change, but has promised that a discussion paper on climate change will be released in 2002.


9 See http://www.nrc.gov/reactors/decommissioning/funding.html.

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NB Power applies shadow pricing of $15/tonne to evaluate the investment alternatives it has considered. It is not clear that this evaluation criteria could be publicly acceptable if broadly implemented. If the $15/tonne were actually applied to NB Power’s emissions in the Year 2000, rates would have increased by 15%, an increase that would make rates for most customer classes in New Brunswick the highest in Canada, except for PEI where the rates are indexed to 110% of New Brunswick’s rates

NB Power has a range of alternative low-carbon and no-debt alternatives that it might pursue as an alternative to the Point Lepreau reinvestment. Purchases from Hydro Quebec or Labrador would both come from low carbon hydro-electric sources. Gas-fired cogeneration replacing a combination of NB Power’s forecasted low carbon nuclear production and high carbon coal-fired production could achieve a carbon-dioxide neutral alternative to the retubing of Point Lepreau. During the recent refit of the Irving Oil Limited Refinery in Saint John, the refinery was pre-engineered to incorporate cogenerated power production. Refinery cogeneration is commonly used around the world. It is often twice as efficient as conventional fossil generation, creating opportunities for lower cost power and reduced environmental emissions. Based on NB Power’s interrogatory responses PNB #3 and CCNB #89, approximately 7.1 TWh of gas-fired cogeneration production would be needed – 5 TWh to replace PL and 2.1 to offset coal emissions – to achieve carbon neutrality relative to the planned future.

Lessons on the Potential Pitfalls of Utility Central Planning from Ontario

In the years leading up to its financial collapse, Ontario Hydro engaged in a massive long term central planning exercise that ultimately resulted in the 25 year Demand/Supply Plan. That plan was published in December 1989, subjected to extensive public hearings, and was ultimately withdrawn in 1993.

The Demand/Supply Plan proposed the construction of 6 to 14 new Darlington-sized CANDU reactors, significant CTU capacity, major programs for DSM and non-utility generation, and many other initiatives. The originally estimated cost of the entire program including interest was approximately $100 billion.

Among the assumptions underpinning the plan that proved faulty were assumptions that electricity demand would never decline, that retubed nuclear reactors would operate reliably, and that electricity prices would steadily decline.

Many major stakeholders endorsed the plan including the Association of Major Power Consumers in Ontario representing industrial users, major unions, and the Ontario government. Other key stakeholders, including the Municipal Electric Association and the Independent Power Producers Society of Ontario, supported major elements of the plan.

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Many observers in Ontario complained that the Demand/Supply Plan process failed because no new investments were committed through the process. An alternative view is that the Demand/Supply Plan process ultimately succeeded in avoiding a massive increase in debt for a power system which only a few years after the collapse of the plan became recognized as burdened by economically unsupportable historic debt.

NB Power’s analysis supporting its retubing investments echos the approach used by Ontario Hydro in the Demand/Supply Plan. For example, the same discount rates are applied to relatively low risk investments and relatively high risk investments. In addition, the load forecast uncertainty is assumed to grow less after 10 years (see NB Power’s interrogatory response to CCNB #10.) Technological uncertainties inherent to the investments being proposed were assumed to be fully reflected in the analysis. As in the Demand/Supply Plan, NB Power is taking little or no account of market risks, such as consumers responding to higher prices by cutting their demand or self-generating.

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New Brunswick expects backing in bid for Canada-first gas

Canadian Press
Globe and Mail
May 6, 2002

FREDERICTON — The New Brunswick government says it will have the backing of Quebec, at least one other Maritime government, and powerful Ontario interests when it makes its case to the National Energy Board for a guaranteed Canadian share of Sable Island gas reserves.

The Conservative government of Premier Bernard Lord is preparing for a hearing in July when it will pitch the cause of economic nationalism versus the lure of U.S. dollars in its bid to get gas to northern New Brunswick and Quebec, rather than have it simply sold to the highest bidder.

Energy Minister Jeannot Volpe said the governments of Quebec and Prince Edward Island will support the province’s application for a Canada-first policy governing the sale and distribution of gas from offshore Nova Scotia.

As well, he said Enbridge Inc. of Toronto is backing New Brunswick, along with Montreal-based Gaz Métropolitain and Co. LP, which is involved in a proposal to build a pipeline from Quebec to northwest New Brunswick. Mr. Volpe said it’s only fair that Canadian needs are met before Sable gas is sold to the United States.

But critics dismiss New Brunswick’s application as short-sighted, parochial and based on the same kind of thinking that gave rise to the much-maligned national energy program of the 1980s.

Tom Adams of Energy Probe, an industry watchdog, said he’s surprised the National Energy Board has agreed to hear the application.

“This proposal could only scare away investment in new gas exploration in the Maritimes.”

Mr. Adams said he’s amazed the Lord government had the gall to pitch the idea so close to a scheduled energy forum arranged by the New England governors and Eastern Canadian premiers. The forum, in Saint John next week, will include such participants as U.S. ambassador to Canada Paul Celluci.

However, supporters of New Brunswick’s position say it has a lot of popular appeal and is grounded in common sense.

Ian Doig, editor of the energy newsletter, Doig’s Digest, said from Calgary the proposal has merit and deserves to be heard by the National Energy Board.

“There don’t seem to be any specific ground rules for Canadian content,” Mr. Doig said.

Lori MacLean, spokeswoman for EnCana Corp., the energy giant recently created by the merger of PanCanadian Energy Corp. and Alberta Energy Co., said the company is waiting to see more details of New Brunswick’s application before completing its intervention. Ms. MacLean said the company has not yet sold any gas from its Deep Panuke project off Nova Scotia, set to begin production in 2005.

“No gas from Deep Panuke has been sold to anyone, including any customers in the United States,” Ms. MacLean said. “Nothing has been committed and we’re open to offers.”

 

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Indo-Pakistani nuclear war? CANDU!

Alex Roslin
Saturday Night
May 1, 2002

In uncertain times, small things can make all the difference. One December 13, 2001, a wrong turn by a driver in New Delhi may have saved the planet from a nuclear Armageddon. That morning, five heavily armed men driving a car packed with explosives slipped past guards at the Indian Parliament. After mistakenly turning into a lane used only by Vice-President Krishnan Kant, they tried to reverse but rammed into Kant’s official vehicle. A scuffle broke out with the vice-president’s security detail, and the terrorists started shooting. They killed eight security personnel and a gardener in a 40-minute firefight before being dispatched themselves. One terrorist managed to fire through Kant’s office door, narrowly missing him. Another gunman made it within metres of a doorway used by Indian Prime Minister Atal Bihari Vajpayee before being killed.

India blamed its rival Pakistan for orchestrating the attach and sent hundreds of thousands of troops to the border of the two countries, where there was heavy exchange of gunfire. Vajpayee said war was under consideration. Both sides put their nuclear missles on alert. “If we go to war, jolly good!” declared India’s top military chief, General S. Padmanabhan, adding that the country was prepared for a nuclear war and would not hesitate to annihilate Pakistan.

After several weeks of bluster and troop movements, an edgy calm was eventually restored. The global community was left to imagine what might have happened had the terrorists had better directions and done a Columbine at the legislature, then filled with 300 lawmakers and officials.

The long-simmering feud between India and Pakistan may seem far away, but there is real reason for Canada to feel embarrassed and ashamed about its role in allowing the tensions in the subcontinent to have potentially apocalyptic consequences. Canada’s program of exporting nuclear reactors – as economically dubious as it is strategically questionable – played a major role in the development of nuclear weapons in both India and Pakistan. Canada sold heavily subsidized reactors to both countries through the 1960s and 1970s, as evidence mounted that both wanted the bomb and would use Canadian technology to build it. The goal of exporting reactors, motivated largely by the suspect prestige that would come Canada’s way from nuclear sales, overrode issues like proliferation and global security. South Asia was left to live with the legacy.

Since September 11, that legacy has been put into stark relief. The security of Pakistan’s nuclear arsenal is being questioned after reports that pro-Taliban Pakistani military officers could overthrow President Pervez Musharraf and leave the country’s bomb arsenal up for grabs. Also worrying is news that top retired Pakistani nuclear weapons scientists met with Osama bin Laden to discuss his plans for acquiring a nuclear device. The expertise of at least one of these men is traceable to Canada.

In February, the Bulletin of the Atomic Scientists moved its symbolic Doomsday Clock two minutes closer to midnight in response to the Indo-Pakistan conflict and fears about nuclear terrorism. It warned that the threat of a nuclear war was closer than at any time in the past 15 years. Canadian hands might easily be accused of having helped wind that clock. “Whenever you provide a country with nuclear technology, even for the production of power, you contribute to the weapons expertise of that country,” says Sean Maloney, a war studies professor at the Royal Military College in Kingston, Ontario. “It’s not too much of a leap.”

Like two childhood friends now past their prime, the bomb and Canada’s nuclear program have had their share of adventures to reflect on. The Canadian program was a baby of the Manhattan Project – the top-secret U.S. effort to build the first bombs during World War II. Canada has a third of the world’s uranium supply, and a mine on the shore of Great Bear Lake in the Northwest Territories produced much of the uranium for the earliest U.S. bombs. Equally vital to the Manhattan project were Canadian scientists at secret laboratories in Montreal and Chalk River, Ontario. The Canadian efforts were recognized for scientific brilliance, and the war left Canada with the second-largest nuclear research infrastructure in the world after the U.S. Of the 50-odd reactor designs that were circulating in the 1940s and 1950s, only two have survived until today: one Canadian, one American. The Canadian design, the NRX, was the most powerful reactor in the world at the time. It was specifically designed to produce weapons-grade plutonium and would supply much of the U.S. military demand for years to come.

Canadian scientists reminisce with pride about these early years. “It was a glorious time for us,” says Gil Bartholomew, the retired director of the physics division at Atomic Energy of Canada Ltd. (AECL), the federal agency that designs reactors and sells them in Canada and abroad. “I’m sure glad I was there then and not now.”

Canada would end up playing a role not only in the U.S. bomb program but also in those of Britain and France, as scientists in those countries embarked on weapons programs based on the Canadian research after the war. Unintentionally, Canada’s labs also contributed to the Soviet A-bomb project when the KGB infiltrated Chalk River before being exposed by Igor Gouzenko, a defector from the Soviet embassy in Ottawa.

“What other country has been involved in so many nuclear weapon programs? I can’t think of one,” says Gordon Edwards, the Montreal-based president of the Canadian Coalition for Nuclear responsibility. “And always it’s in this typical self-effacing low-key Canadian way, saying, ‘What, oh me, did I do all that?”

Over the next decades, the Canadian nuclear establishment would seek to parlay its early military achievements into the construction of civilian power reactors at home and around the world. It was one of Canada’s few high-tech industries with a big export potential, and there were handsome economic spinoffs – or so nuclear officials assured. There was also the prestige that came from membership in the rarefied club of nuclear nations.

Behind it all was a quasi-religion of nuclear boosterism in which the high priests were scientists and the gospel was atomic power as a clean, limitless fuel source of the future. The gospel was enshrined in President Dwight D. Eisenhower’s Atoms for Peace program, which sought to promote nuclear energy around the world. India, with its huge and exploding population and limited resources, was the ideal candidate. In 1956, it became Canada’s first customer for a nuclear reactor.

There is little question that the sale of the CIRUS reactor was of dubious economic benefit. Canada essentially gave the $17-million reactor to India as a foreign-aid project, with the Canadian government covering more than half of the cost with an outright grant. Based on the powerful NRX, which supplied plutonium to the U.S. weapons program, CIRUS was also a highly efficient factory for plutonium. Canada’s contract with India said the plutonium created by CIRUS ws not to be used in nuclear weapons. But Canada, caving to Indian pressure and eager for its first nuclear beachhead in the developing world, had not insisted on controls to make sure that didn’t happen.

The reactor was online only two years when the security situation in South Asia deteriorated dramatically. In 1962, China defeated India in a war over disputed border territory. The conflict changed Indian thinking about strategic matters, not so much because of any threat posed by China, but rather because of India’s feeling that its international stature had suffered. Indians, until then overwhelmingly opposed to the bomb on moral grounds, started calling for nukes as a way of restoring national pride.

None of this had any noticeable impact on Canada. The Indo-Chinese war had broken out in the middle of negotiations with India for the sale of the new CANDU.

Canada, once again, was eager to provide fantastic subsidies. The financing negotations were still going on when Dr. Homi Bhabha, the father of India’s nuclear program, gave a crystal-clear indication that India was interested in acquiring the bomb. Speaking to an international conference on disarmament, he declared that a “country with a huge population, such as China, must always present a threat to its smaller neighbours, a threat they can only meet either by collective security or by recourse to nuclear weapons to redress the imbalance in size.”

For anyone who might have missed his point, Bhabha also noted that “any knowledge of operating a reactor for peaceful purposes can be employed later for operating a reactor for military purposes.” He then proceeeded to detail precise steps a country could take to exploit a foreign-supplied reactor for a clandestine bomb program.

The speech had no apparent impact on the negotiations or nuclear relations with Canada. In April 1964, Canada concluded a generous financing agreement for the 200-megawattRajasthan Atomic Power Plant-1, giving India a low-cost $37 million US loan to pay for Canadian technology and services that came with the $76-million RAPP-1 reactor. Canada threw in, free of charge, all the design and technical information for construction of the reactor, which ultimately enabled India to build a network of so-called “CANDU clones.”

While preparations were under way for construction to start on the CANDU, tensions in Asia increased again. In October 1964, China tested its first nuclear device. A month later, India’s prime minister reversed the country’s long-standing opposition to nuclear explosives.

The developments spread concern around the world – everywhere, it seems, except in Canada. Ottawa could have suspended the RAPP-1 reactor deal, cut off subsidies or halted other co-operation. But Canada’s nuclear ties with India kept expanding. Construction of the first CANDU went ahead in August 1965. In December 1966, Canada signed another agreement with India to sell a second 200-megawatt CANDU power reactor, the RAPP-2, in another heavily subsidized deal.

In Washington, U.S. State Department officials were getting nervous. In March 1966, the department sent a cable to the U.S. embassy in New Delhi warning that India had made enough technical strides to explode a nuke “within a year following such a decision.” The cable, obtained through the Freedom on Information Act by the National Security Archive, a nonprofit group based in Washington, D.C., also warned that India was diverting plutonium from the reactor into weapons. Burning uranium in the CIRUS and other Canadian reactors creates plutonium, a radioactive material that does not occur naturally. The uranium fuelling the CIRUS, much of which came from northern Canada, was reportedly being removed prematurely in such a way as to maximize its plutonium content. “While this circumstance alone does not necessarily indicate that a decision has been made to develop nuclear weapons,” the cable said, “it hints strongly that suitable material is being produced to permit the rapid implementation of such a decision.”

A former head of India’s nuclear regualtory agency confirms that fuel was being prematurely removed and says Canadians at the site knew it was happening. Adi Gopalakrishnan says, however, that the fuel was removed prematurely only because of problems with the aluminum covering for the uranium fuel rods, called the cladding. “Later, there was a realization that [India] had a stockpile for a bomb.”

A retired AECL senior manager who helped oversee nuclear collaboration with India in the 1960s agrees that Canadian technicians stationed at CIRUS would have known about the plutonium diversion. But the manager, who requested anonymity, says he had never heard of any problems with the cladding, which Canada used itself in its own reactors. He says Canadian officials were loath to protest any fuel diversions out of fear that this would disrupt relations with India. “We were just interested in the science. Nobody really wants to rock the boat,” he says. “It’s quite obvious there was not enough vigilance. Certainly more could have been done.”

Reid Morden, who spent much of the 1960s with the external affairs department, including a stint as a Canadian nuclear disarmament negotiator, confirms that Canadian officials were concerned about fuel diversion at the time. “The presumption always was that they were diverting plutonium,” says Morden, who later went on to become director of the Canadian Security Intelligence Service and president of the AECL.

The knowledge didn’t compromise Canadian-Indian relations. Even after the U.S. Joint Chiefs of Staff warned in 1967 that India “will probably detonate a nuclear device within the next few years,” co-operation with Canada expanded. One reason Canada and the U.S. so wilfully overlooked India’s nuclear ambitions was Cold War politics. India was seen in the West as a bulwark against Mao’s China. State Department officials at one point in the 1960s even toyed with the idea of giving India the bomb as a way to counterbalance Beijing’s atomic program. India, wracked by food shortages and trying to establish a post-colonial profile, artfully played Washington off Moscow and sought the bomb to pump up its stature on the world stage. Worries about nuclear proliferation proved to be no match for these political intrigues and machinations.

When, in 1974, India finally detonated “the Smiling Buddha,” an eight-kiloton underground nuclear explosion at Pokhran, near the border with Pakistan, it was an event people in the know had almost grown tired if waiting for. Still, official – if disingenuous – indignation was called for. International inspectors were sent to knock on doors in non-nuclear states to check for illegal diversion of radioactive material into weapons. Canada and the U.S., among others, slapped sanctions on both India and Pakistan – the latter had vowed to build a bomb in response to the Smiling Buddha. Nuclear weapons, which the big five nuclear powers had been stockpiling for years, suddenly became a fixture of international debate and treaties.

No country pretended to more outrage than Canada. After the Smiling Buddha, Canada cut off two decades of nuclear co-operation with India, pulled out its nuclear technicians and suspended sales of atomic materials. The Canadian nuclear establishment expressed mortification, insisting it had had no idea India was building the bomb. The official view was one of shock and surprise, along with reluctant acknowledgment of Canada’s role.

Morden maintains the Smiling Buddha was the last thing Canadian officials expected. “If there is one thing we have really been constant on, it is that we have been on the forefront of trying to restrict nuclear weapons,” he says. “I don’t think we had the slightest desire, interest or purpose in looking the other way,” he says.

But the Canadian declarations of distress have caused much eye-rolling among proliferation experts and scientists. “If you don’t want India to develop nuclear weapons, don’t sell them a power reactor and act all surprised that they developed the bomb,” says George J. Lolos, a sub-atomic physicist and head of the physics department at the University of Regina. “There was no surprise. Give me a break.”

If Canada was happy to turn a blind eye to India’s ambitions to obtain nuclear weapons, Pakistan wasn’t. As early as 1964, according to a declassified U.S. State Department cable, Pakistani President Ayub Khan “expressed his deep concern at [the] prospect of rapidly developing Indian nuclear capability which could be readily converted from peaceful to war-like purposes.” In March 1965, The Manchester Guardian reported that the “spectre” of an Indian bomb “haunted” Pakistan’s leaders. Foreign Minister Zulfikar Ali Bhutto famously told the newspaper that if India produced nuclear weapons, “then we should have to eat grass and get one, or buy one, of our own.”

Pakistani fears were so strong that some academics believe they were a key factor in Pakistan’s initiating its 1965 war with India. They argue that Pakistan saw the war as a final opportunity to grab the long-disputed border territory of Kashmir before India obtained the bomb. The war left 20,000 dead or wounded; Kashmir remained part of India.

The previous year, Canada had signed an agreement with Pakistan to build the 137-megawatt Karachi Nuclear Power Plant (KANUPP). The outbreak of war with India had no impact on Canada’s involvement in the region and most of the $63-million US expense for the new CANDU reactor was financed with low-cost Canadian government loans. Construction of the new reactor started in August 1966, and the reactor came online in October 1972. During those years, the region’s stability went from bad to worse. In 1971, Pakistan became embroiled in another war with India and in a civil war tha tresulted in the partition of the country. A Canadian engineer who helped manage the KANUPP project recalls the wobbly security situation at the time. “We had to stop work for a while,” says William Brown, who was in charge of engineering development at the KANUPP. “Construction was interrupted for nine to 12 months (out of concern for) the security of Canadian personnel. We were getting a little nervous having our staff there.”

In January 1972, construction of the reactor was not yet complete when Bhutto, by then president, convened a secret meeting to launch Pakistan’s nuclear weapons program. As in India, the Canadian reactor sale meant the transfer of nuclear material, training, infrastructure and equipment to Pakistan that, according to proliferation experts, became the foundation for the country’s bomb program. Pakistan didn’t conduct its first nuclear tests until 1998, but it is generally believed to have acquired a nuclear-explosive capability in the late 1980s. Unlike India, Pakistan did not use plutonium derived from Canadian uranium in its bombs. Proliferation experts do, however, suspect that Pakistan diverted plutonium from KANUPP for nuclear weapons research.

Canada quietly resumed nuclear technical assistance to both Pakistan and India in the late 1980s. It kept flowing even after both countries conducted tit-for-tat nuclear tests in 1998. The nuclear aid was provided so surreptitiously that even Lloyd Axworthy, then foreign affairs minister, was apparently unaware of it. When confronted by reporters about the aid after the 1998 tests, Axworthy was adamant that Canada had no nuclear contacts with Pakistan or India. Two days later, Prime Minister Jean Chrétien acknowledged the aid but defended it as being purely for safety purposes. But many nuclear experts say the assistance also helps the weapons programs of both countries by teaching their scientists how to run reactors more efficiently. Especially problematic, they say, is the fact that Canada has provided aid to India’s network of CANDU-clone reactors, which operate outside of international controls and are believed to produce plutonium for weapons.

Officially, the Canadian nuclear establishment denies any responsibility for bringing nukes to South Asia. “I know for a fact that the CANDU reactor, the fuel, whatever, cannot be used to do that,” says Louise Duhamel, the AECL’s general manager of communications. Another AECL official, David Lisle, says Canadian-supplied reactors are under “stringent” international controls to ensure fuel is not diverted into weapons. Brown, the engineer at the KANUPP project, says the Pakistanis he worked with had no interest in weapons. “All of the guys who came to train in Canada were very sincere guys who were just interested in operating a power reactor.”

But a broad range of scientists, proliferation experts and government officials say Canada’s contribution was fundamental. “The story would begin with the Canadian help,” says Ashok Kapur,chair of the ipolitical science department at the University of Waterloo and author of several books on the nuclear programs of India and Pakistan. “CANDU technology was the starting point.” Zia Mian, a Princeton University physicist and expert on nuclear proliferation in South Asia, agrees. Canada’s role was “absolutely indispensable,” he says. “Without it, India, especially, would not have gotten nuclear weapons.” A senior U.S. State Department non-proliferation official, who spoke on condition of anonymity, said the Canadian-supplied nuclear infrastructure “facilitated the development of nuclear weapons. It provided a foundation on which a nuclear weapons program could be built.”

Canada’s role, say the experts, went well beyond being the source of the plutonium for the Smiling Buddha and selling Pakistan a reactor on the cheap. Perhaps the most important Canadian contribution to the South Asian bomb was training for the first generation of Indian and Pakistani nuclear experts. Some 260 scientists and engineers from India and up to 50 from Pakistan trained at Canadian reactors like Chalk River and Point Lepreau, New Brunswick. Many went on to work in weapons development.

“By having a buddy relationship with other nuclear scientists, you can pick up all sorts of things,” says Gordon Edwards of the Canadian Coalition for Nuclear Responsibility. “Facts, properties of materials, research information that can help with development of nuclear weapons. You learn scuttlebutt, the things that went wrong. So much of it is done just by rubbing shoulders and talking.” The revolving door between India’s and Pakistan’s civilian and military nuclear programs meant Canada was effectively providing apprenticeships for future bomb makers. A case in point is the man who co-ordinated India’s secret preparations for the 1974 Pokhran test, P.K. Iyengar. A physicist, he trained at the AECL’s Chalk River research lab before going on to head India’s nuclear weapons research centre and India’s Atomic Energy Commission, which runs the country’s civilian and military nuclear programs. Iyengar was a frequent visitor to Canadian reactors even after the Smiling Buddha, arranging trips through old friends in the 1980s and 1990s.

Perhaps the most notorious example is Sultan Bashiruddin Mahmood, the Pakistani nuclear engineer who reportedly tried to help Osama bin Laden get the bomb. A report from an Indian think-tank, the South Asia Analysis Group, said Mahmood was “believed to be Canadian trained.” But both the AECL and Foreign Affairs refuse to provide the names of Indians or Pakistanis who had come to Canada to train.

Mahmood came to prominence in the early 1970s when he designed a device to detect water leaks at the Canadian-supplied Karachi Nuclear Power Plant – a device for which he holds two patents in Canada. He later spearheaded work on a research reactor near Islamabad that experts believe can produce about 100 kilograms of enriched uranium a year, enough for half a dozen bombs. He was also the chief designer of a plutonium-producing reactor that, according to experts, has played a major role in Pakistan’s bomb program. Mahmood eventually rose to become director-general of nuclear power at the Pakistan Atomic Energy Commission.

Through the years, Mahmood made little effort to hide his extreme religious views. An outspoken admirer of the Taliban, he openly advocated that Pakistan follow in the footsteps of the fundamentalist Afghan movement. He also penned bizarre papers arguing, for example, that harnessing genies could solve Pakistan’s energy problems. “He is a kook,” says Zia Mian, the Princeton physicist.

Mahmood was forced to retire in 1999 after, it is said, calling for large-scale production of weapons-grade plutonium to furnish other Islamic countries with nuclear weapons. Bitter toward the government, Mahmood entertained close ties with the Taliban and, according to The Washington Post, eventually had “extensive” meetings with Osama bin Laden and other al-Qaeda officials to discuss nuclear weapons before September 11.

Experts are divided on how successful bin Laden has been in his atomic ambitions. U.S. officials say he does not yet possess a nuclear bomb, but there is evidence he was able to acquire some nuclear material. Pro-U.S. Afghan forces reportedly discovered low-grade uranium in oil drums and metal boxes left behind by fleeing al-Qaeda forces at the Kandahar airport in December; the uranium could have been used to make a so-called “dirty bomb,” a crude radioactive device wrapped arounda conventional explosive.

There is a consensus that Pakistan, because of its instability, is, after Russia, the most likely country where terrorists or other rogue forces could procure a nuclear device or bomb material. Experts warn that Mahmood’s al-Qaeda contacts reflect a broad pro-Taliban sympathy in Pakistan’s powerful intelligence, military and nuclear establishments. And they point out that rising tensions in Pakistan are closely linked to the latest strife with India. CIA director George Tenet told the U.S. Congress in March that the chances of a war between Pakistan and India are “higher than at any point since 1971” and warned that a conventional war could easily escalate into a nuclear confrontation. Indeed, a retired Pakistani brigadier who advises deposed prime minister Benazir Bhutto was quoted in a recent issue of The Atlantic Monthly saying he hopes to see a nuclear war with India before he dies. “We should fire at them and take out a few of their cities – Delhi, Bombay, Calcutta. They should fire back and take Karachi and Lahore. Kill off a hundred or two hundred million people. . . . It would teach all of us a lesson. There is no future here, and we need to start over. So many people think this.”

Why would Canada risk proliferation of nuclear weapons and the consequences to global security in order to export reactors? What could warrant taking such a gamble?

The explanations vary. Some point to the economic benefits of reactor sales for Canada. In a 1993 study commissioned by the AECL, Ernst & Young said that through generation of electricity at home and reactor sales abroad Canada’s nuclear industry had pumped $23 billion into the economy since 1962, creating 30,000 direct jobs. The firm calculated direct federal subsidies to AECL at $5 billion.

But anti-nuclear researchers David Martin and David Argue criticize the study for exaggerating the benefits and minimizing the costs. They came out with a rival study in 1996 that said Ernst & Young had counted some jobs twice and even three times, not included recent layoffs, included civil service jobs in the nuclear total and misinterpreted the nuclear industry’s own figures. Actual nuclear employment, they said, was 18,400.

As for the economic impact, Martin and Argue reported that the nuclear program had been sucking Canada dry. With inflation factored in, the federal government’s subsidies were actually $13 billion since 1952, not including billions more in indirect funding and provincial subsidies. All told, federal inputs actually amounted to a staggering “opportunity cost” of $120 billion (the return of an average investment for that length of time), the researchers said. “Canada’s economy would have been much better off if the government had simply used the AECL subsidies to reduce the national debt,” Martin and Argue wrote.

Independent figures seem to confirm that the industry is a money pit. In 1995, University of Lethbridge economist George Lermer calculated that federal subsidies to the AECL had cost about $73 billion, based on the opportunity cost of the investment. “Like a fire the nuclear industry has been a creator of economic activity but a destroyer of wealth,” says Norm Rubin, director of nuclear research at Energy Probe, a Toronto energy-policy think-tank.

Cold War politics motivated much of Canada’s nuclear policy. George J. Lolos, the University of Regina physicist, says anti-Soviet intrigue often shaped the nuclear decisions of Canada and the U.S., fogging over proliferation concerns. “One has to take into account that the Soviet bloc was a threat, and India was seen as a big counter-bloc in Asia.” Later on, when Pakistan’s bomb program was hitting its stride in the 1980s, the West again turned a blind eye, he said, because Pakistan was the staging area for the U.S. covert war against the Soviet Union in Afghanistan. Pervez Hoodbhoy, a nuclear physicist at Quaid-e-Azam University in Islamabad and noted proliferation expert, agrees: “They were supporting the [Afghan] mujahedeen and they turned the other way to this monster they were creating. It was expediency and lack of principles that brought them this gift.

For Canada, reactor exports also meant entrée into the rarefied nuclear club and international circuits of power. “In the times it was done, you have to try to understand the context,” says Reid Morden, the former AECL president. “[India] was a new Commonwealth nation moving out of colonization. If the Indians did a deal with you, there was a tremendous amount of respect for what they had done. As well, we were very anxious to sell CANDU technology.”

Posted in Nuclear Proliferation | Leave a comment

Bidding opens for Ontario electricity

Janet McFarland
Globe and Mail
April 30, 2002

TORONTO — Ontario’s electricity market opens for trading tomorrow morning, but the drama begins today for Dave Goulding, who heads the Independent Electricity Marketing Organization (IMO).

At 7 a.m. EDT, in a control room in Mississauga, the IMO will begin accepting bids and offers to sell and purchase electricity in Ontario’s newly deregulated marketplace.

By tomorrow morning, the data gathered today will provide the basis to conduct the first trades under Ontario’s controversial new power marketing and sales system.

“I think it’s almost inevitable there will be some volatility when the marketplace opens,” Mr. Goulding predicts.

“We’re trading in a product that moves at the speed of light,” Mr. Goulding says. “We’re dispatching [electricity] every five minutes. The demand and the supply change continuously. So inevitably there are always small perturbations in the price from moment to moment in this business.”

Ontario has followed the lead of numerous jurisdictions worldwide by deregulating the generation and sale of electricity. Ontarians are deeply divided over the move, and all eyes will watch the IMO’s trading data to see whether prices will soar under an open-market trading system.

As the man who runs the trading floor, Mr. Goulding is making no promises to consumers about the early days of trading.

“I anticipate it will be a very interesting time, one way or the other,” he says.

Ontario’s electricity deregulation is proceeding despite a court ruling last week that has delayed the province’s plans to sell Hydro One, which operates the province’s major power lines. Opening the market for electricity trading is unrelated to the ownership structure for Hydro One, and has had no impact on the IMO’s preparations.

The IMO, with a staff of 400 and revenue of $370-million in 2001, was one of five independent companies created by the breakup of the old Ontario Hydro in 1999. It has traditionally controlled the movement of electricity across Ontario’s power grid from producers to utilities and other users.

Its new mandate is far broader. The province has appointed the IMO to oversee the wholesale trading of electricity under the new system. It will operate the computer database that links 240 wholesale buyers and sellers of electricity, and will regulate and police the trading system. The IMO’s Web site will allow consumers to track electricity prices throughout each trading day.

That means electricity generators such as Ontario Power Generation and Bruce Power will register offers to sell electricity, and buyers such as local utilities and major industrial consumers will register bids to purchase. The wholesale spot price of electricity will be adjusted every few minutes based on the supply and demand considerations of market players.

This will be a big change for Ontario, where electricity rates have long been regulated by the Ontario Energy Board. Until a rate increase was approved last year, rates were unchanged for nine years after the provincial government imposed a cap following spiralling price increases during the 1980s.

“We’re going to see volatility for the first time,” says Tom Adams of Energy Probe. “For the first time, Ontarians will be subject to floating prices for the commodity, where the price is formed on the basis of supply and demand.”

Virtually everyone has a different prediction about how rates will change in coming months.

Mr. Adams believes the commodity price of electricity will be volatile, but is likely to fall on average, although factors such as an unusually hot summer or equipment problems at power plants could always change things.

He points to recent declines in the wholesale price of electricity in U.S. markets as an indicator of what Ontario may experience.

In the Pennsylvania, New Jersey and Maryland (PJM) interconnection – the largest trading hub in the United States – wholesale prices have been lower than Ontario’s for months. Last Friday, for example, the PJM average price was 2.7 cents per kilowatt-hour (converted to Canadian dollars), compared with a wholesale price of 4.3 cents per kilowatt-hour for retail customers in Ontario. Prices in northern New York state have been lower than Ontario’s for the past couple of months. (A kilowatt-hour represents the energy required to light one 100-watt bulb for an hour. A terawatt-hour is equal to a billion kilowatt-hours.)

Mr. Adams said even higher prices in Ontario would be better than those that have been traditionally kept artificially low. They have contributed to losses at Ontario Hydro and rising debt levels.

“Historically this artificial stability was achieved at a very high cost, but it was a hidden cost. So nobody really appreciated the real costs underneath it.”

Deregulation consultant Jan Carr says greater transparency of costs is one of the underappreciated benefits of an open market.

“Before, there were hidden cost subsidies,” he says. “Sure you were getting cheaper electricity, but at the expense of higher taxes. That should not happen any more.”

Mr. Carr, who works for consulting firm Barker Dunn & Rossi in Toronto, believes consumers – whose bills will reflect monthly average prices – will not see excessive increases, even if there are short periods of peak prices.

That’s because about 30 per cent of Ontario’s customers – residential, commercial and industrial – have signed fixed-price supply contracts, which will have a calming effect on prices. As well, he says Ontario has structured its system to require OPG to sell some generation plants quickly to encourage a competitive environment.

Nonetheless, Mr. Carr believes prices in Ontario must rise gradually because they were too low to cover the costs of the system, contributing to Ontario Hydro’s rapidly rising debt.

Critics of deregulation are convinced Ontarians will face rising prices, pointing to experiences in other jurisdictions such as California and Alberta.

Paul Kahnert, who heads the Ontario Energy Coalition, argues that deregulation has a poor track record worldwide, and says publicly owned power systems have a track record of producing cheaper electricity than privately owned systems. The coalition includes consumers, unions, environmental and social interest groups.

Mr. Kahnert says a private system must build in profits that will come out of consumers’ pockets.

“How are we going to get cheaper hydro rates when you add in profits to generators, profits to distributors, profits to retailers, dividends to investors, and commissions to commodities brokers?” he asks.

Mr. Kahnert will not reveal how his group will continue its battle after the market opens tomorrow, but warns there will be more court action taken against deregulation.

For his part, Mr. Goulding at the IMO believes there will be upward pressure on prices because current rates don’t reflect the true cost of producing the commodity.

But he believes that the old monopoly Ontario Hydro allowed costs to soar out of control. The high debt has left the system in no position to build more generation plants to meet future demand.

“This is a change that’s being made for the long term,” he says.


The Independent Electricity Marketing Organization (IMO) is one of five companies created by the breakup of Ontario Hydro in 1999.

How Ontario Hydro was broken up:

Ontario Power Generation, producer Hydro One – distributor Ontario Electrical Financial Corp. – holds Ontario Hydro debt

Electrical Safety Authority – IMO The IMO’s mandate is to regulate and police the wholesale trade of electricity in the province. It will monitor interactions between buyers and producers.

Producers will offer their power for sale through the IMO. Buyers will bid to purchase through the IMO trading system.

Ontario electricity stats

Sales breakdown:

Residential 27%

Industrial 34%

Commercial 39%

Annual sales Export to U.S., -12 TWh* Domestic, 140 TWh* (valued at $6.8-billion U.S.)

*TWh = Terawatt hours

 

Posted in Reforming Ontario's Local Electrical Distribution Sector | Leave a comment

Electricity Metering Part II

Tom Adams and Allen Stanbury

April 12, 2002

International Experience 

Australia

Paralleling the approach adopted in the Distribution System Code, a public interest group in Australia called the Public Interest Advocacy Centre argued in a report issued in May 2000 that customers without interval meters should not have to make any contribution to the cost of metering improvements. Their study assumes that small customers will not respond to price. The study suggests that the best way to reduce inter-customer cross-subsidies is to perform load research to do load profiles for customers with different levels of demand. The study does not address the positive externalities of interval meters. Electricity prices in Australia’s electricity market, NEMMCO, are much less volatile than has been demonstrated in North American markets.7

Customers selecting Florida Power and Light’s power quality program receive automated notification of power outages and power quality events. At the customer’s cost, Florida Power and Light replaces the existing electromechanical meter with one capable of two-way wireless connection to an automated trouble response system.

The electronic meter will detect and record events such as power outages, monetary interruption, high/low voltage and voltage/current unbalance. The meter automatically notifies the Florida Power and Light trouble system when an event occurs. The trouble call software then notifies the customer by pager, fax or Internet email of the occurrence time and dispatches a trouble crew via wireless communications. The trouble crew can view the details of the trouble and the archived event log, in the truck on the way to the call. Revenues from the new service offering cover the cost of the new metering and wireless communications system.8

Customer uptake has been largely small to medium commercial and industrial customers but similar offerings are under active consideration for residential customers.


7 See http://www.reggen.vic.gov.au/docs/electric/piacmeter.pdf

.

8 Conference paper, “One Year Post Deployment: Florida Power & Light’s Implementation of C&I AMR with Power Quality Monitoring”, Ed Malemezian & Ed Brill, Metering Americas 2001.


Florida Power and Light also offers a direct control load shedding program to residential consumers. Participants in the “Residential On-Call” program get two load control transponders installed for free on appliances of their choice. When called these appliances are shut off for no more than an hour a day. Most customers are called only a few days per month.9

A participating customer receives a fixed refund of, up to $161 US per year, whether the customer’s load is shed or not. Over 750,000 customers have enrolled in this program. Florida Power and Light also has a “Business On-Call” program and have a total of over 600 MW of load under direct control. Being able to cap demand avoids the need to construct millions dollars worth of generation and reduces fossil-fired emissions at the same time.

Summary

The potential benefits of interval metering to consumers include: improving the customer’s opportunities to avoid price excursions, protecting customers from intra-class cross-subsidies due to the NSLS, increasing the fairness of MPMA customer rebates, helping customers quantify power quality/reliability, and facilitating power quality/reliability monitoring.

The potential benefits of interval meters to the electricity market at large include: reducing the amplitude of price excursions, mitigating potential abuses of market power, and enhancing demand/supply reliability.

The potential benefits of interval meters to society at large include: facilitating greater energy conservation (peaking plants tend to have worst emission profiles) and lower distribution utility capital requirements from fine-tuned transformation requirements.

Analyzing the benefits of advanced meters is complicated by a number of uncertainties. Lifecycle costing of advanced meters is driven by capital cost, Measurement Canada verification requirements, communication costs, and distribution utility operating costs such as dealing with failed communication links. Customer response to future fluctuating prices in Ontario is uncertain.

The value of advanced meters is a function of volatility but forecasting volatility is inherently uncertain.


9 http://www.fpl.com/savings/on_call.


Appendix

On March 8, Energy Probe’s presented a summary of our research on interval metering to a meeting of the Ontario Independent Electricity Market Operator’s (IMO) Market Surveillance Panel and representatives of the IMO’s Market Monitoring Unit

Posted in Power Generation in Ontario | Leave a comment