Shocking news! Electric bills are going up right now

Posted on December 20, 2000 by energyprbe

John Stewart
Mississauga News
December 20, 2000

Hydro rates are going up.

The Ontario Energy Board (OEB) has approved a 2.6 per cent increase in hydro rates for Enersource Hydro Mississauga customers to take place immediately.

This means a residential consumer using the average of 1,000 kilowatt-hours of power will see the bill rise by $2.06 from its current $78.15 to $80.21.

The OEB approved only the first phase of Hydro Mississauga’s rate application. The utility has asked for an additional 1.49 per cent increase when the electricity market opens sometime next year, and then hikes of 4.18 per cent in 2002 and 2003.

That would represent a total increase for residential consumers of 12.54 per cent over three years. “Our rates are still extremely competitive, if not the best,” points out Ken MacDonald, Enersource public affairs manager.

The increase approved is necessary to provide a reasonable profit to the City of Mississauga which now owns the utility, MacDonald said. At the same time, the phased rate, “ensures that we do not burden customers.”

However, a spokesman for an energy watchdog organization predicts the increase is the beginning of the end for consumers.

Tom Adams of Energy Probe said the deregulation of the electricity industry in Ontario is, “turning into a major disaster for consumers.”

“We anticipate that when the music stops, the ordinary consumer will be paying prices about 20 per cent above our existing rates,” said Adams.

As the rates increase, the players will start pointing the fingers at each other to try to assign blame, said Adams.

His advice to consumers is to “keep your eye on the bottom line.” Keep your old bills and compare them with what you will be charged in future.

Adams thinks consumers should be upset about the “totally unnecessary” increases he blames on mistakes by the OEB and Energy Minister Jim Wilson. The minister should have anticipated that municipalities, who now have the right to operate utilities as profit-making commercialized entities, would take full advantage, argues Adams. The result has been “a huge hidden windfall” for municipalities who took cash out of utilities and put their utilities into debt.

“There’s a real risk that municipal politicians will treat this windfall as party money,” he said. While Toronto has already spent much of the money it took out of its utility, Adams said Mississauga has been much more responsible in putting its money into a separate account and not spending any of it.

MacDonald agreed with Adams that it’s possible energy costs could rise in the future.

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

Biomass breakthrough cuts heating costs and greenhouse gas emissions

Posted on December 18, 2000 by energyprbe

News Release
December 18, 2000

For Immediate Release

STE ANNE DE BELLEVUE, QUEBEC, December 13, 2000— A new agricultural energy system that turns fast growing grasses into a low-cost, environmentally friendly means of heat energy is set to change North American energy markets. REAP-Canada and Dell- Point Technologies made the announcement today following the successful commercial pelleting of switchgrass on the weekend at an alfalfa pellet plant in Ste. Marthe, Quebec.

“Our mission was to create useful energy applications by maximizing the amount of solar energy that could be collected in fields, while minimizing the energy used to grow and process the material” said Roger Samson, executive director of REAP-Canada. “Research in the US proved that switchgrass could be an efficient solar collection system, but until now, no one has been able to figure out how to make a useful energy product from the material without subsidies.” In reference to Canada’s climate change strategy, Samson stated, “We don’t need to be paying for carbon sinks to reduce our greenhouse gases emissions when we can save 30-50% on heating costs by using biofuels.”

Dell-Point Technologies of Blainville, Quebec joined forces with REAP to come up with the switchgrass pellet biofuel system. Mark Drisdelle of Dell-Point Technologies said, “We knew that the woodfuel pellet heating industry, although currently attractive, was going to eventually run short of quality wood residues, so we designed a pellet fuel combustion technology to burn more difficult fuels such as bark and agricultural fibres. We just didn’t expect switchgrass to so quickly become such a viable option.”

REAP and Dell-Point tested various agricultural biofuels for producing pellets. Switchgrass proved economical as it lowered processing costs by being easier to pellet and required minimal drying compared to wood. The grass could also be produced in closer proximity to energy markets. Pelleted switchgrass in the Dell-Point stove burned at the same efficiency as oil in a high efficiency oil furnace.

Tom Adams, Executive Director of Energy Probe, a national consumer and environmental watchdog said, “Here is a cheap, convenient, and comfortable renewable heating system that gives consumers a real alternative to the sky high conventional energy prices. The pellet fuel system has reached the point where homeowners can leave behind the atmospherically damaging fossil fuel industry for meeting their heating needs.”

The Dell-Point Technologies pellet fuel stove is currently being marketed at http://www.pelletstove.com. The company is seeking investors to optimize their proprietary technology to develop a complete line of furnaces and stoves for burning grass pellets. Natural Resources Canada and the Ontario Agricultural Adaptation Council support the switchgrass biofuel program.

(30) Backgrounder What is switchgrass? Switchgrass is a native warm season, perennial grass that was one of three dominant grass species of the North American tallgrass prairie. It has been under investigation by the US Department of Energy since the mid 1980’s as a bioenergy feedstock. REAP-Canada was the first organization in Canada to begin working with the grass as a biofuel. Three hundred acres of the grass are now planted in Eastern Canada for biofuel applications. The grass is a resource efficient species that grows with minimal inputs of water and fertilizer compared to conventional farm crops.

How much energy can be grown? On average a yield of 10 tonne/ha can be expected in most areas of North America. Each tonne of material contains the same energy as 3 barrels of oil. If 20 million hectares (50 million acres) of farmland were planted, the equivalent of Alberta’s agricultural land base, the biofuel production would be 200 million tonnes, or the energy equivalent of 600 million barrels of oil.

How much energy does it take to make the system work? The complete fuel cycle (farm production of switchgrass, chopping, pelleting and household delivery) has a net gain of about 11 barrels of oil energy equivalent per acre. This compares favourably to other commercial biofuel alternatives. Corn ethanol, for example, only produces enough net energy on one acre to replace 1.5 barrels of oil. Corn also requires moderate to high quality farmland for its production; switchgrass can be grown on lower quality lands.

How much does it cost? In Eastern Canada, the cost of switchgrass production is estimated to be $46-$68/tonne delivered to a pellet plant. Pelleting is estimated to cost about $60/tonne. Assuming a farm price of $120/tonne, switchgrass pellets provide the same cost for heating as oil at 25 cents per litre or a delivered natural gas price of 25 cents per cubic metre. In Eastern Canada, heating oil is selling at 50 cents per litre and natural gas prices are continuing to rise. Switchgrass pellets are only half the cost of conventional fuels for farmers. Off-farm energy consumers in agricultural regions can expect switchgrass pellets to save them about 30% on their bills compared to oil and natural gas. Bulk handling systems are available to provide similar convenience as fossil fuels.

What about greenhouse gas emissions? Switchgrass pellet heating reduces greenhouse gas emissions by 93% compared to oil heating. Combustion of each barrel of oil emits 487 kg of CO2 to the atmosphere. Fifty million acres of perennial grasses could reduce CO2 emissions by 275 million tonnes per year if used to substitute oil.

For further information visit:

REAP Canada’s web site http://www.reap.ca under reports/agri- fibre/bioenergy
Dell-Point Technologies web site at http://www.pelletstove.com (1-877- 331-6212)
Pellet Fuels Institute at http://www.pelletheat.org
Energex Pellet Fuel at http://www.energex.com

Contact :
Patrick Duxbury REAP-Canada (514) 398-7743 ext. 2
Mark Drisdelle Dell-Point (514) 865-6214
Tom Adams, Energy Probe (416) 964-9223 ext. 239

For media kits call REAP Canada at (514)-398-7743

 

Posted in Renewables | Leave a comment

Is There Stress Corrosion Cracking in Pickering ‘A’?

Posted on December 14, 2000 by Other News Sources

Dr. Michael Moles
Transcript of CNSC Public Hearing
December 14, 2000

THE CHAIRPERSON: We will then move to the oral presentation by Michael Moles. That is presentation 00-H29.13A.

MR. MOLES: Good evening, Dr. Bishop, Commissioners and everyone else.

My name is Michael Moles. I was a long-time employee of Ontario Hydro Technologies and a reactor inspector. The question we have today is: Is there stress corrosion cracking in Pickering A?

What it really means is: Are Pickering A reactors safe? And in safe we are really referring to: Can we have a multiple LOCA?

The first question is: Is there stress corrosion cracking at Pickering A? I am going to try and do this in only semi-technically terms, because this is basically a technical presentation.

The most serious concern we have is the circumferential stress corrosion cracking in the feeder pipes, and we will get through all that in a few minutes.

First of all, a history of CANDU problems, many of which I have actually worked on.

The CANDU reactor is unique, as you all know, and it has certain generic problems. The history of CANDU, at least from an operating point, is a history of surprises. Something goes bang, and we can jump in and do something about it.

We have had a series of problems. There has been a string of pressure tube problems. there has been a number of steam generator problems, and now we seem to be looking at feeder pipe problems, all from the primary heat transport system.

The solution almost invariably is OHN or OPG, or OPN as it may be called now, has engineered the CANDU system out of its problems. They have changed pressure tubes. They have fixed up steam generator tubes, and so forth.

I will quickly run through first pressure tubes and steam generators and then on to feeder pipes.

The CANDU pressure tube reactor is a very interesting and novel design. I think it is quite a good one actually. It does have unique problems. It is a unique system. And invariably the reactors have the final say on the problems.

What has happened is that all the researchers I used to sit next to would predict that there would not be a problem with creep, but unfortunately they got the creep in the wrong direction, this kind of stuff.

One of the problems is that simply the scientific knowledge is limited, and there is very limited amount of in-reactor data.

Here is an example. Pressure tubes roll joint cracking. The reactor got it right; we didn’t.

Axial versus circumferential creep: the reactor got it right.

Deteriorating ingress, hydride blisters — and that was PG16 — the reactor got that one right.

Fracture toughness and some more recent ones, manufacturing defects. Bruce 2 NO6 is a very good example. Darlington Vibration, that was reactor. Debris fret marks, again that came from the reactor. Abnormal fuel support marks, we found that out from the reactor. Hard garter spring detection, which is a Point Lepreau problem, we found that out from the reactor.

Basically, the reactors win them all. So our target shooting is not that good.

With steam generators we have done slightly better, because other people have steam generators, even though we have different materials, particularly in Pickering A, and we do have some different operating conditions.

Again, the reactors have the final say.

Once one problem starts to appear, typically there is another bunch. Again we go to the same solutions: inspect, repair, replace, plug, control chemistry and operating conditions.

There is the score on steam generators, most of which you know. And it is not complete.

Feeder pipes seem to be the latest CANDU-specific component to start to show some problems. The only two that have really popped up so far are erosion/corrosion, which is universal, and the one axial SCC problem failure that we had in Point Lepreau.

Unfortunately, there has been very little inspection performed. The only inspection has been ultrasonic wall thickness measurements for erosion/corrosion, and this is not adequate at all to find any form of cracking.

We have very little knowledge on the state of material. To the best of my knowledge, nobody has done anything like strain gauge steam feeder pipes.

So we have to ask the question: Are there other potential failure mechanisms coming?

We can look at the feeder pipes over here. We can see we have these two over here: the erosion/corrosion, the axial stress corrosion cracking. These are another bunch of typical problems that can occur. After all, these are just carbon steel pipes. There is nothing particularly special about them, except they are an unusual material.

What are feeder pipes?

They are long carbon steel pipes that feed the PHT coolant into and out of the reactor, which essentially cools the fuel. The main problem, from an inspection point of view, is that they are very inaccessible. They are surrounded by end-fittings, and most of the internal portions or the long length of them can’t be touched at all from that side.

In practice, they are long, bent, somewhat dirty and corroded. Their radiation fields are very high. You can really only hang on to them for a few minutes.

Unfortunately, they are so close together that you can barely push your hand through. So there are a lot of physical constraints in inspecting feeder pipes.

This is pretty much what they look like. This is the face of the CANDU reactor over here, and these are all the feeder pipes coming off. There is one per pressure tube or fuel channel, so there are hundreds and hundreds of these things. These lengths here can rum up to 10 metres on a strip.

Typically, the access is very limited at the front and a few points along here unless you get into the feeder cabinet itself.

Along these zones here there is virtually no access at all.

This is what they look like close up. These end-fittings are two-and-a-half metres long, so you can literally only put your arm in and just catch the first bit down here near the graylocs.

The geometry is complex. There are several different sizes.

What happens if a feeder pipe fails?

If you get a “break before leak” situation, especially with a guillotine failure, then you can have some serious problems.

The first problem is you lose your coolant. The other problem is you potentially get whiplash. These feeder pipes are very long lengths with no supports whatsoever. If one of them goes under high pressure and high temperature, they can whip around and start smacking into other components. This is a relatively well-known problem in the engineering world.

This means that we can have potential multiple failures.

These feeders are typically bunched together in groups of nine. I was only at Point Lepreau, and I think it is nine at Point Lepreau. If you lose nine channels, you have a problem.

The other problem is that we don’t even know where they are going to fail, because there is an awful lot of places where they could fail.

So there is a number of serious failure mechanisms: manufacturing defects — we can forget that one for the moment; erosion/corrosion, probably not likely; corrosion fatigue, possible; stress corrosion cracking, very possible.

Just a few words about SCC.

It is not a well understood phenomenon. Nobody can predict whether you really have it or not. It kind of happens. It is a big problem in gas pipelines.

You need three things: you need a tensile stress; you need a material that can crack; and you need a suitable environment.

It is a very slow growth mechanism. It can take decades, and it can produce brittle failures, and very brittle failures with no warning.

It is not widely common in carbon steels, but it has happened in Point Lepreau feeders and it has also been seen in Pickering A calandrian vault. And it has been seen in a number of other things like gas pipelines. That is really the example right now.

This diagram comes from the NEB on gas pipelines. You need your three conditions: your environment; your tensile stress; and your pipe material.

We know from the fact that there has been one stress corrosion crack failure in Point Lepreau that you have to have your material susceptible and your environment must be susceptible.

You have these two factors already, so all you are really looking for is the stress.

These are the cracks. They are nasty little objects that wander all over the screen. They are typically multi-faceted and hard to find, and they can remain dormant for decades. You can discover that your material is full of nasty little cracks.

Can Pickering have SCC?

Well, the material and environment are suitable. The stress could easily come from bending. Those feeder pipes, if you remember the pictures, are very long; and as your reactor heats and cools during start-up and shut-down, you get thermal type stresses.

In the thermal portion of Ontario Hydro, as it used to be, they used to have this problem in a very serious fashion, because they were always what they called two-shifting, which is starting up in the morning and shutting down in the evening. There were all kinds of cracks in there.

If you have that kind of situation going on in Pickering, then you potentially have circumferential stress corrosion cracking and possible failure.

Quite frankly, there is nobody in this room or anywhere who can tell you whether we have SCC in there at the moment. Maybe it has and maybe it has not. It is not something that we can predict, like fatigue cracking, and so forth.

Unfortunately, very few inspections are being performed. There is high dose and very limited access, particularly for cracking. What has been done has been for erosion/corrosion, and that does not count.

To the best of my knowledge, there have been very few analyses done. I don’t think anybody has done any strain gauging. There is probably not much point in doing any stress analysis because we have so little idea as to what the actual stresses would be.

We didn’t find any SCC at Point Lepreau, but it was a relatively new reactor compared with Pickering A.

What we need to do is inspect; and if we find something, we need to repair it, weld it, replace it, whatever is the appropriate thing to do. But above all, we need to inspect.

I will give you a few conclusions.

First of all, the CANDU history indicates that we are going to get some more failures. This has been an historical fact. Quite frankly, the most likely candidate is the Pickering A feeder pipes. They have been totally neglected, just like pressure tubes were before PG16.

The most likely candidate is probably circumferential stress corrosion cracking. The problem with this is that it could lead to a LOCA and multiple channel failure.

Again the solution is engineering. We don’t want to go through a lot of R&D stuff. R&D is not helping us at all in stress corrosion cracking.

What we would like to recommend is we select the reactor with the most effective starts, whichever one of the Pickering A reactors it is. We can work that out. And effective here means that a brutal shutdown or start-up is likely to be more effective than a lot of gentle ones.

We use ultrasonic guided waves as a “go-no go” sorting tool. These we can fire down those long, long pipes, which are quite suitable for this kind of a technique, from the few accessible locations: the corners of the Graylocs and maybe from up in the feeder cabinet.

Then we need to develop a little scanner that runs along selected feeder pipes to fully analyze any damage. Hydro-Quebec has already developed a little scanner like this. It is actually for erosion/corrosion, but it is the kind of device that could be modified to look for cracking. This is a feasible technology.

When we find out what is actually in there, somebody can make an intelligent decision.

Just in case you are interested, these are my qualifications. I am grossly over-educated. I have spent almost 20 years in automated ultrasonics. I also spent three weeks in Point Lepreau and did quite a lot on feeder pipes, developing the technique, writing the procedure, and actually crew bossed one of the feeder pipe inspections.

Thank you very much.

THE CHAIRPERSON: Thank you, Mr. Moles.

We frequently have issues over feeder pipes brought before us.

Are there any questions?

Dr. Giroux.

MEMBER GIROUX: This is a very interesting presentation. I would like to hear reaction from OPG.

MR. STRICKERT: Mr. Pierre Charlebois, our Chief Nuclear Engineer, will speak to this.

MR. CHARLEBOIS: Thank you and good evening.

First of all, I would like to give you a bit of an overview of our life cycle program that we have in place for the feeder pipes that were referenced in the presentation.

We have under way, in fact, a program to inspect many of these feeder pipes with some of the tooling that is being discussed here. In fact, we are looking at making use of the GenTE(ph.) tooling itself for measuring the thickness and the conditions of the feeder pipes.

Maybe we need to put this into context.

We have currently 300,000 feeder operating years of experience. That is 28,000 feeder pipes for 15 years. We have had one failure.

The failure that occurred at Point Lepreau was an actual crack that formed in the feeder pipe. The conditions that led to that particular failure are a bit unique. The pipe supports were not in the correct location. The fuel channel itself was not locked into proper position.

The chemistry conditions on the heat transport side on the inside of the pipe were somewhat unusual at the time as well as a result of a separate incident that occurred. Therefore, it is entirely possible that the mechanism that took place was in fact caused by those particular conditions all acting together, as indicated by the presentation, causing the stress corrosion cracking.

In our particular plants we do not have the same support arrangement. In making sure that the supports are free to move, to make sure that the stresses are maintained below acceptable level, is something that we continuously pay attention to. In fact, we do adjustments on the reactor to move those supports and make sure they are in the proper position.

The last point I would like to talk about is we actually monitor the chemistry conditions of the system as well, to make sure that we don’t have a condition that could cause essentially attack of the material itself.

In a nutshell, we have a comprehensive program as we speak today at the Darlington plant. We are doing 100 per cent inspection of an elbow area where we see the most evidence of not stress corrosion cracking but erosion/corrosion.

Those in fact are being measured at the Darlington plant. This is an ongoing program to baseline and characterize the state of the feeder pipes, to make sure that we manage the life of the components appropriately.

THE CHAIRPERSON: Thank you.

MEMBER GIROUX: Essentially, if I understand correctly, you are sort of in agreement with Mr. Moles and acting on this with engineering solutions and inspections?

MR. CHARLEBOIS: Of course the discovery of I believe it was Channel S08 at Point Lepreau when the incident took place caused us to re-examine the scope and the completeness of our programs for feeder pipes. That has been expanded considerably in the industry over the years.

In fact, we have a considerable program in place already to assess the conditions of our feeder pipes.

MR. MOLES: May I comment on that, please?

THE CHAIRPERSON: Yes, go ahead. Then I want some comments from staff.

MR. MOLES: All the inspections being done at Darlington are irrelevant to stress corrosion cracking. They look exclusively for erosion/corrosion. You need an entirely different technique.

Second, anything — the water chemistry may or may not be important. With stress corrosion cracking, it crops up under a wide variety of conditions. It still does not mean that even if the chemistry is different at Point Lepreau from what it is in Pickering, that you are not going to get stress corrosion cracking.

THE CHAIRPERSON: I do want to look at the relationship to EA versus the operational maintenance and inspection aspects, but I do want some comment from staff.

MR. WADDINGTON: Thank you, Madam Chair.

First of all, the EA itself includes a nuclear accident, as we discussed before, which captures the accident. This is clearly a detail as part of the licensing review.

I am going to ask Mr. Jim Blyth to discuss the response in some detail; thank you.

Mr. Blyth.

MR. BLYTH: Thank you very much.

I have a couple of thoughts.

Certainly the accident that has been included in the EA bounds any credible consequences of a feeder failing. So I don’t believe that Dr. Moles’ presentation has any fact on what has been predicted or assessed in the EA.

OPG is right. There are over 300,000 feeder years of experience in Canada alone. There is another almost 5,000 feeders in overseas reactors. We have seen this once in quite a unique situation.

Certainly it is something that should be addressed going forward by inspection programs, having seen it once.

The other comment I would make is that steam generator tubes and certainly pressure tubes are rather exotic materials. Carbon steel is not quite as exotic. It is widely used in the nuclear industry in the process systems and all sorts of other industries.

There is a large body of experience with respect to this material, and stress corrosion cracking is a pretty rare occurrence.

THE CHAIRPERSON: Dr. Barnes…?

MEMBER BARNES: I would like to get clarification from Mr. Charlebois.

Do I understand that you will be examining the feeder pipes in Pickering A for stress corrosion cracking in the near future; and if the answer is yes, could you give us some indication of the scope of that investigation?

MR. CHARLEBOIS: I would like to clarify that with my colleagues. There is a program to examine the conditions of the feeder pipes on the Pickering reactor, certainly to measure the thickness of the feeder pipes.

I do not have at my fingertips the scope of that particular program at the present time.

I think you should note that of all the reactors, in terms of erosion/corrosion, the Pickering reactors are the least susceptible to the mechanism. We have observed that in the past. We have measured that in the past.

Therefore the extent of the program on those reactors is of a lesser extent. It is more prominent on the CANDU 6 and the Bruce and Darlington design.

This is the erosion/corrosion program.

In terms of the SCC process, it is very difficult to actually measure stress corrosion cracking in carbon steel unless the mechanism is obviously active. The best remedy is to prevent the conditions from existing.

That is to make sure that the supports to the feeder pipes are in the proper position; that there is no interference between the feeder pipes as you saw in the picture; and that the chemistry conditions of the reactor are maintained within the specifications.

Those aspects are regular programs that we have in place to make sure that those positions are proper in all of our units, including the Pickering reactors.

MEMBER BARNES: I am just trying to correlate a point that Mr. Moles is making with your reply. He is focusing more on the SCC problem rather than erosion/corrosion, and you are saying you are doing erosion/corrosion at Darlington, and you have implied that there is some work going on at Pickering.

I am trying to establish whether you are in fact looking at the SCC problem in Pickering A?

MR. CHARLEBOIS: What we are doing at Pickering A is verifying in fact that the conditions of the supports and that the clearances between the feeders are such that the stresses during operation will not be excessive and therefore will not initiate the SCC process.

I am trying to explain that it is very, very difficult to detect the beginning of SCC in materials using today’s technology. It is a difficult process. You will detect it once a crack has started to form.

At Point Lepreau, for example, after they detected the one failure on S08 — which I might add, by the way, because of the nature of the carbon steel, which is a very ductile material, it was detected before it actually caused any loss of coolant.

They inspected, I believe, close to about 150 to 200 other channels to try to see if there was any evidence of crack formation or propagation, and they did not find any at that time.

THE CHAIRPERSON: Mr. Blyth, you wanted to make a comment?

MR. BLYTH: Yes. I think it is important to recognize that we have one isolated event of this occurring. It did leak before it broke — well, it did leak; it never did break. In fact, under very, very unusual circumstances, highly unusual circumstances that have not been replicated elsewhere.

I don’t believe it has been demonstrated that this mechanism is in fact active in these reactors. I believe the one incident can be explained.

THE CHAIRPERSON: Thank you.

Are there any other questions?

Thank you very much, Mr. Moles.

MR. MOLES: It was a pleasure.

Posted in Nuclear Plant Security | Leave a comment

Hydro customers lost in the dark

Posted on December 11, 2000 by energyprbe

Martin Mittelstaedt
Globe and Mail
December 11, 2000

Deregulation leaves millions of people with no way to know which firm offers the best power deal 

For Helen Nolan, the recent notice from her local electricity company was a puzzle.

An affiliate of Toronto Hydro was offering a contract to supply all the electricity she’d use for a year at what it called “a good fixed rate” of 5.65 cents a kilowatt-hour, or about the amount of power that would keep a 100-watt light bulb shining all night.

“The literature was confusing,” Ms. Nolan said. “I don’t have anything to compare [it with] and I don’t know what all is involved.”

In recent weeks, electricity competition has arrived at the doorsteps of Ontario’s four million residential power customers. And so has confusion and criticism. Some experts are warning that consumers could be bamboozled into signing long-term contracts for power at excessive prices.

“Right now, in my opinion, the sheep are being fleeced,” says Tom Adams, executive director of Energy Probe, a Toronto environmental and consumer advocate, referring to the public.

Mr. Adams is critical because the contracts are offering power at costs that could be more than 20-per-cent above what rates are likely to be when competition officially begins next year.

Although no one knows exactly what rates will be when Ontario’s market opens, one estimate commissioned by the Ontario Energy Board, the provincial regulatory body in charge of consumer protection, projected 4.2 cents a kwh.

If the estimate turns out to be accurate, anyone who has signed a contract now could be a big loser.

Electricity suppliers defend their rates, saying they are offering consumers the security of a guaranteed price, much in the same way that some homeowners desire long-term mortgages as insurance against a spike in interest rates.

Those signing long-term electricity contracts will do well if prices soar under a competitive market.

“It’s the same rationale you would go through if you were choosing a mortgage. Do you want a variable rate or do you lock in? If you lock in, you generally pay a slightly higher rate,” said Blair Peberdy, vice-president at Toronto Hydro.

Under the government’s competitive market plan, consumers who don’t select a supplier will automatically receive the going wholesale market rate for power. That rate will fluctuate depending on supply and demand conditions.

The sales pitch by suppliers is causing added consumer uncertainty because it’s such a novelty. For more than nine decades residential consumers haven’t had to think twice about buying electricity. Rates in Ontario and almost everywhere else in Canada have been set at the cost of production by government-owned power monopolies.

Under Ontario’s new plan, consumers will also pay additional charges for the delivery of their power and for retiring the debt of Ontario Hydro, the defunct provincially owned electric utility. Many of these costs are now consolidated on electricity bills, but a new billing format under the competitive market will show totals for each item.

A review of electricity contracts currently offered indicates it is almost impossible for buyers to make an informed judgment on the deals, some of which would lock purchasers into five-year fixed-priced contracts worth thousands of dollars.

Some of the electricity marketers include affiliates of Toronto Hydro, Hydro One Inc., formerly part of Ontario Hydro, and Direct Energy Marketing Ltd., a subsidiary of British energy company Centrica PLC.

Although some consumer products are distinguished by quality, power is the same regardless of supplier because the electrons that make up electricity are identical, so price and duration of contracts are the crucial considerations.

But because no independent sources are posting electricity prices, consumers have no yardstick by which to evaluate what they’re being offered.

Many of the sales contracts also contain a clause in the fine print that gives the suppliers the rebates consumers would have received under a government plan to protect ratepayers against surging power prices. Some also have hefty cancellation fees.

Mr. Adams of Energy Probe said the electricity contracts are almost impossible for non-experts to understand. “Unless you’re heavily involved in this [electricity] restructuring debate, you wouldn’t know what they’re talking about,” he said.

He is also critical of the energy board, meant to be a consumer watchdog, for not being more aggressive in helping consumers navigate the contracts.

In response to concerns about consumer confusion, the board issued a pamphlet last month warning ratepayers to be careful when approached by power suppliers.

The rate study is available on the board’s Web site, but the document is highly technical and difficult for a consumer to find unaided.

The confusion for consumers has been accentuated by a timing glitch in the way the government has allowed deregulation to proceed.

Initially, the government wanted the open market to begin this year. But the date was postponed until an unspecified time next year.

In the meantime, the OEB licenced nearly 40 electricity marketers to sell power. They’ve been fanning out over Ontario, vying with each other to sign up customers both large, like the major power-consuming companies, and small buyers, like Ms. Nolan.

All this frenzied selling activity, with door-to-door sales pitches and promotional brochures, is taking place even though consumers don’t have to sign with anyone to keep their lights on and toasters running, Mr. Adams said.

Electricity contracts

Price per kilowatt hour Term (years) Cancellation penalty Waiver of government price protection
Direct Energy 5.36¢
5.95¢		 1st year
2nd to 5th		 1.5 kwh Yes
Toronto Hydro 5.65¢ 1 year None Yes
Hydro One To be determined when market opens Up to 5 years 10% of contract’s value Yes
Ontario Energy Board price estimate 4.2¢ – – –
No contract signed Fluctuating market rate N/A None No

Sources: OBB & Companies

Posted in Natural Gas Utility Regulation and Commodity Deregulation | Leave a comment

Ottawa consumers brace for 17% jump in natural gas bills

Posted on December 8, 2000 by energyprbe

Kristin Goff
The Ottawa Citizen
December 8, 2000

Home heating could cost $1,600

Natural gas prices are going through the roof this winter, creating increases of $500 or $600 in the annual bills for many typical households and a $25-billion hit to Canada’s manufacturing industry.

For consumers in the Ottawa area, that translates into an expensive winter.

Only three months after its last rate increase, Enbridge Consumers Gas is close to getting a 17-per-cent increase in natural gas rates, effective Jan. 1. That new increase, which analysts feel is a virtual certainty, could add roughly $115 to annual annual heating costs — on top of increases approved in October.

In total those past and pending increases mean a typical home will cost $1,500 to $1,600 to heat this year, up from $980 last year, according to Enbridge spokesman Mike Campbell.

(The example is for a family of four in a 1,500 square foot home with a natural gas furnace and water heater.)

While Mr. Campbell says Enbridge currently has no plans to apply for any further rate increases, others suggest it almost certainly will.

“In the current environment, I think it is realistic to anticipate we’re going to get the one (increase applied) for January, and then another one hard on its heels, maybe in February,” said Tom Adams, president of Energy Probe, a Toronto consumer and environmental group.

Enbridge’s latest rate application asks for an increase of 3.65 cents to 24.4 cents per cubic metre of natural gas. But prices have climbed so quickly on commodities markets — setting records in each of the past six sessions — that prices are well above Enbridge’s latest price increase.

The January contract for natural gas hit a record $9.24 U.S. on the New York Mercantile Exchange yesterday before closing at about $8.37 U.S. per British thermal unit, or about 37 cents Cdn per cubic metre and 12.5 cents higher than Enbridge’s latest rate application.

Not all Enbridge customers will see the rate increases Jan. 1, assuming the Ontario Energy Board gives its approval. Since the deregulation of the gas industry several years ago, half of Enbridge Consumer Gas customers –about 750,000 people — have signed on with independent suppliers, whose gas is still delivered by Enbridge for consumers in the Ottawa area.

Those with long-term contracts with other suppliers might escape the pain for a while, but anyone renewing a supply contract any time soon will face a big price increase.

The pain will also spread to businesses, whose own contracted natural gas costs will be double what they paid last year, according to Jayson Myers, chief economist for the Canadian Manufacturers and Exporters Association.

“A doubling means $5 billion in added costs for manufacturers,” who may also see other prices, like electricity increases in areas where natural gas is used in generated power.

Mr. Myers argues that in today’s highly competitive global economy, Canadian companies will have to swallow those higher costs, knocking 25 per cent off the profit margins of manufacturers in Canada over a year and perhaps leading to cuts and layoffs.

“The impact is going to be felt particularly in energy intensive industries,” he said. Those include steel, paper, concrete, petrochemical, and agrifood industries, along with many smaller businesses operating on thin margins.

Natural gas prices have spiked upward on fears of a shortage this winter. Low prices, until recently, offered little incentive for producers to increase exploration or pipe-line capacity. That didn’t create major problems in the past couple of years, when winters were warmer than normal, said Mr. Adams of Energy Probe.

Prices have been rising all year but forecasts of a huge Arctic cold wave — nicknamed a Polar Pig by some analysts — increased fears that North America might face a serious shortage of natural gas.

There was some price relief on commodity trading in New York yesterday, suggesting some traders felt recent record high prices had been overdone.

Mr. Adams suggests natural gas prices could quickly fall if the weather hits a surprising warm streak.

 

Posted in Natural Gas Utility Regulation and Commodity Deregulation | Leave a comment

Higher hydro rates predicted

Posted on November 14, 2000 by energyprbe

Martin Mittelstaedt
Globe & Mail
November 14, 2000

Deregulation, debt loads, market forces will see users digging deeper, experts say.

The Ontario electricity market, the biggest in the country, is about to be jolted by higher and more volatile power rates, according to industry experts.

The expected rise, which is difficult to quantify, is a result of the government’s twin program of deregulating the industry and integrating it more closely with the U.S. power market, where rates are under upward pressure due to higher natural gas prices.

“Rates are going to go up. When the public figures out what has been done to them I think they’re going to be very upset,” said Tom Adams, executive director of Energy Probe, an environmental and consumer advocate organization.

The government has also allowed its distribution utility, Hydro One Inc., to go on an unprecedented acquisition spree.

It has quietly spent about $500-million in the past few months to take over about one-third of the province’s local power companies, paying above market prices for some of the assets.

Many industry experts are baffled by the actions of Hydro One, which is one of the successor companies to Ontario Hydro and delivers electricity mainly in rural areas of the province.

Industry experts, such as Mr. Adams, are worried Ontario’s venture into deregulated power could turn into a fiasco of the kind experienced in Alberta and California, where higher prices and supply problems have occurred.

“This electricity restructuring is morphing into an attack on consumers, taxpayers and the environment,” Mr. Adams said.

Until now, Ontario’s $10-billion electricity market has been run as a non-profit, government co-operative, with the province owning most of the generating stations and the transmission grid, while municipalities owned local companies that delivered the electricity to most consumers.

Under the policy changes, these electricity suppliers are being told to operate on commercial terms, make a return on their investments and make payments in lieu of taxes to the province to help retire the debt incurred by the old Ontario Hydro.

Competition in the generation of electricity is also being allowed, while the province’s four million power- ratepayers will be permitted to select the electricity supplier of their choice, starting next year, much like deregulation in the telephone and natural gas industries.

Under the new system, rates will fluctuate on a day-to-day, hour-to-hour basis, according to supply-and-demand.

This is a change from the previous system, where rates were fixed annually based on the cost of supplying electricity.

As an efficiency move, the province has also encouraged the rationalization of local power-distribution companies by granting a tax holiday on mergers between those owned by government entities.

Under the tax break, which ended last week, the number of local distribution companies plunged to 91 from 230.

However, Ontario still has far more than the 25 that exist in the rest of the country.

Distribution costs account for only about 15 per cent of the total price of electricity for taxpayers, so any efficiency savings from the rationalization are expected to be small.

Mr. Adams said the requirement for the sector to earn commercial returns will likely raise overall power rates by about 7.5 per cent over the next three years.

Hydro One purchased 88 of the local distribution companies during the tax holiday, boosting its customer base to 1.2 million a rise of about 25 per cent. Its biggest purchase was a $260-million deal for Brampton Hydro, covering 83,000 customers at a cost of about $3,100 per customer.

Some industry analysts believe Hydro One overpaid by more than 50 per cent on this purchase.

“We would have thought something under $2,000 per customer,” said Tony Jennings, executive director of the Municipal Electric Association an industry trade group. “It is quite interesting that their shareholder is allowing them to do this.”

Bu Hydro One defended the acquisition. Rod Taylor, executive vice-president, said Brampton is in a rapidly growing part of the GTA, and the utility was willing to pay a “strategic premium” to expand into a major urban market.

He said electricity distributors have grossly inefficient ownership structure, compared with other energy sectors, such as natural gas, where there are only two major companies in the province.

 

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

Why Pickering-A Should Not Be Restarted Without Approval by an Independent Panel Review

Posted on November 14, 2000 by Other News Sources

Norman Rubin

November 14, 2000

Energy Probe’s comments to the Canadian Nuclear Safety Commission on the Pickering A – Return to Service, Environmental Assessment SCREENING REPORT – CNSC Meeting, December 14, 2000

Norman Rubin is Energy Probe’s Director of Nuclear Research and Senior Policy Analyst

Like a few of the staff of the CNSC (then called the AECB), I participated extensively in the Federal Environmental Assessment Review of Atomic Energy of Canada’s (AECL’s) plan to bury Canada’s high-level nuclear waste in a deep hole in the Canadian Shield. That was an independent Panel Review of the same sort that is required for the Pickering-A restart. I learned many lessons in that Review – several of which were also learned by the CNSC staff participants, and many of which have relevance to the Pickering-A Restart decision. Those lessons include the following:

There is a bigger difference between an independent Environmental Assessment Panel Review and a CNSC review, than there is between a horse chestnut and a chestnut horse.

For example, the AECB/CNSC’s recommendation at that Panel Review was that AECL be given approval to proceed with site selection for its disposal plan. The panel withheld that approval.

AECB/CNSC’s position was that the AECL concept had been shown to be, or was known to be, acceptable and safe. The panel unanimously concluded that the concept was not acceptable, and was divided on its safety, writing two opposing chapters in its final report.

In the context of a process run by intelligent, well-educated nuclear-establishment “outsiders” with a broad range of expertise, the views of AECB/CNSC staff – and the regulatory positions taken by the AECB/CNSC itself – were often revealed to be part of the problem that needed to be solved. Indeed, the independent Panel made extensive recommendations for reform of the AECB itself, most of which have not been implemented.

The differences between AECB/CNSC positions and those of the independent Panel were not primarily based on different opinions of fact, but were primarily based on different values. For example,

AECB/CNSC, like AECL, placed great value on the claims that deep geological disposal could provide “passive” safety, without any need for future intervention; the panel heard that ordinary Canadians didn’t trust such long-term predictions.

AECB/CNSC, like AECL, placed great value on the responsibility of our generation to relieve future generations of costs and responsibilities of dealing with nuclear waste, with unmonitored, irretrievable deep geological disposal; the panel heard that ordinary Canadians (including those in AECL-sponsored focus groups) thought our descendants would prefer to have more choices and control.

As we have outlined in our earlier submissions, it is largely these kinds of non-technical, non-factual values decisions – decisions which AECB/CNSC routinely makes, but (a) on which AECB/CNSC has no special expertise and (b) which AECB/CNSC never faces squarely as the values decisions they are – that make the Pickering-A restart decision so interesting and important and controversial to nuclear-establishment “outsiders”, and so routine and open-and-shut to OPG and AECB/CNSC. If there is an independent Panel Review of this decision, we expect it to be as educational for AECB/CNSC Reactor Licensing staff as the High-Level Waste Review was for the staff of that branch. Among the issues that we predict will look very different to “normal people” than to AECB/CNSC and its staff are the following:

The relative weight attached to Pickering-A’s never-discussed “world class” toxic inventory and to the frequently-discussed “world class” efforts made to keep it contained;(1)

The enormous quantity of verbiage spent (within the nuclear establishment) on the possibility that low-level radiation is less harmful than predicted by the best-fit mathematical model, compared to the mathematically equivalent possibilty that it is more harmful(2);

The scant attention given to the actual estimated health risks of predicted radiation exposures from routine and accidental releases from Pickering-A, compared to the enormous time spent comparing those exposures to radiation exposures from naturally occurring terrestrial radionuclides and cosmic rays from outer space – a comparison often viewed as irrelevant outside the nuclear establishment;(3)

The “discrepancies and dichotomies in the definitions of acceptable risk” in the regulation of radioactive pollution and non-radioactive carcinogens were to have received a scientific review by the federal government, but the review turned to “political science” when the authors decided to reject their terms of reference. Using those “discrepancies and dichotomies”, CNSC routinely permits radioactive pollution levels – and estimated health risk levels – that other regulations and regulators in Canada would forbid;(4)

While the decision to restart Pickering-A will obviously create quantities of highly radioactive fuel bundles and of radioactive tritium – a fact that is very relevant to “normal people” – those quantities are “not relevant” to this “Environmental Assessment” because those wastes will be transported off-site!(5)

The total impacts of exposing people and the environment to radioactive toxins outside the immediate area around Pickering-A are ignored by OPG and AECB/CNSC in the EA, because the individual exposures at that distance have dropped below some arbitrary level – without mention that the number of such exposures has been rising just as fast with distance!(6)

The question of trust – in effect, the answer to the question “Have I ever lied to you before?” – is an essential one to “normal people” put at risk by another, but receives scant attention from AECB/CNSC. For example, I have never heard any spokesperson from AECB correct or contradict a falsely reassuring statement by a licensee, or another government agency. And this Screening Report – apparently issued by CNSC staff – itself contains factual and technical errors.(7)

The questions of the need, alternatives, costs, and benefits of the Pickering-A restart are essential to a considered decision on the subject to “ordinary” Canadians, but are considered irrelevant or “beyond the scope” to CNSC.

“Ordinary” Canadians are almost always more concerned about reactor safety after they learn of the existence and nature of the Nuclear Liability Act, and the protection it gives nuclear operators like Pickering-A’s OPG, in case of a catastrophic accident – like the accidents this EA doesn’t analyze, because they’re so unlikely to occur. But the CNSC administers the Nuclear Liability Act, and led its defense in Court, against a legal challenge brought by Energy Probe, the City of Toronto, and Dr. Rosalie Bertell.

In short, this decision simply cannot properly and legitimately be made by CNSC, because it rests primarily on values on which CNSC has no special expertise, and on which it has already taken a position contrary to the values of “ordinary” Canadians. Moreover, the involvement of CNSC staff in the drafting of a flawed EA for this project further compromises CNSC’s perceived, and actual, independence.

Footnotes:

1. On the former, see EA Addendum, Appendix I, comments-responses #403 and #404 – and especially their completely unresponsive “responses”!

2. See EA Addendum, Appendix I, comment-response #401.

3. See (e.g.) EA Addendum, Appendix I, comments-responses #403 & #405.

4. See (e.g.) EA Addendum, Appendix I, comment-response #421 (Environment Canada).

5. See EA Addendum, Appendix I, comment-response #399.

6. See EA Addendum, Appendix I, comment-response #402. In Appendix L.4, it is revealed that the EA’s reference to a “50 km” radius – repeated in Appendix L, as if it were at least partially correct! – actually should refer to an area that cannot possibly exceed 40 km, at the extreme limit: “· 20 km from water supply plants within 20 km of PNGS” And that area is the largest of those considered. In other words, the population actually considered “worth counting” is significantly smaller than indicated in the EA.

7. In addition to the “20km + 20km = 50km” error noted above, we highlight one error that must surely embarrass CNSC as much as OPG: The presentation of the reason that Pickering-A was shut down in December of 1997 never even mentions the fact that operation after December 31 with its inadequate Emergency Shutdown System would have violated the station’s safety license from AECB – a fact surely known by both OPG staff and CNSC staff! See EA Addendum, Appendix I, comment-response #532 (Town of Ajax).

Posted in Nuclear Safety | Leave a comment

Hydro billing leaves customers in the dark

Posted on November 10, 2000 by energyprbe

Ellen Roseman
Toronto Star
November 10, 2000

Engineer can’t get answer about unbundled bills.

ELECTRICITY BILLS are changing with the advent of a competitive market. But customers may not understand the new “unbundled” bills or how the charges are calculated. Paul Kozma, a retired engineer, has gone to great lengths to figure out his Toronto Hydro bill. He’s spent a year trying to get answers from the utility, the Ontario Energy Board and the Ontario Ministry of Energy.

He even tried to intervene at Toronto Hydro’s upcoming rate hearing, but missed the deadline. “I made a commitment that I will follow a logical route to get to the bottom of this,” Kozma said, asking for our help with the billing issue.

In early 1999, after six former utilities amalgamated, Toronto Hydro redesigned customers’ bills and listed the individual charges that make up the total energy cost.

Unbundling lets you see exactly what you’re paying for each component of electricity and, in the future, compare prices.

The bill had a customer charge (a flat monthly charge for administration); distribution charge (covering the cost of wires running down your street); and energy charge (covering the actual electricity you use).

Kozma is questioning the customer charge, which started at $8.60 a month. Since Toronto Hydro sends bills every two months, his first few bills had a $17.20 customer charge. But in mid-1999, he found a customer charge of $20.64 on his bill.

The billing period was 72 days, he noticed, and the customer charge was pro-rated (72 days at $0.2867) to cover that longer interval.

Checking further, he was told Hydro can’t read the meter every 60 days. The billing period may be longer or shorter because of storms, residential moves, changes in meter reading routes and inaccessible inside meters. When the billing period is more than 65 days or less than 55 days, the customer charge is pro-rated. “In many cases, there is a corresponding adjustment in the opposite direction upon resumption of the normal billing schedule,” said Bruce MacOdrum, Toronto Hydro’s vice-president and general counsel.

Kozma, who tracks his bills on a computer spreadsheet, waited for an adjustment in the opposite direction. But his next bill covered 60 days, followed by others going from 60 to 64 days. He was never compensated for the extra-long billing period in 1999 or the extra customer charge of $3.44. “I’m not after the money,” Kozma said. “It’s the principle.”

His question: Why should customers be penalized when their meter isn’t read within 55 to 65 days, especially when the delay is Hydro’s fault?

Other utilities don’t pro-rate the customer charge, Kozma points out. Enbridge Consumers Gas, for example, charges a flat $10 a month.

Toronto Hydro’s customer charge is now $9.46 a month, or $18.92 every two months and still varies if the meter reading interval is not 55 to 65 days.

“This occurs very rarely,” said Tom Moss, senior communications officer, “in less than 3 per cent of cases. And when it does occur, the amount is less than $3.”

He agreed it’s possible for customers to be overcharged one month and not undercharged later on. “We’re trying to build a system that’s fair for everybody and no system is perfect,” Moss said.

Toronto Hydro doesn’t pro-rate the customer charge to make extra profit, he emphasized. “It’s revenue-neutral for the system.”

But is it revenue-neutral for each customer?

“I’m going to suggest we take another look at this,” Moss said after our third conversation about Kozma. “He may have an issue.”

There’s another issue here: communication. Ontario’s electricity market is in transition, which means utilities should spend a lot of time explaining what they’re doing.

But Kozma got little help from Toronto Hydro, despite numerous calls, letters and e-mails. And there’s no explanation of the customer charge on customers’ bimonthly bills.

The Ontario Energy Board and the Ministry of Energy should prepare people for electricity competition. But they’re not doing enough, said Tom Adams, executive director of Energy Probe.

“I’m very critical of regulators for not giving consumers more useful information,” he said. “When the responsible officials are not assisting the public, there’s an opportunity for retailers to exploit ignorance.”

 

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

Playing the hydro waiting game

Posted on October 31, 2000 by energyprbe

Pierre Marcoux
The Hamilton Spectator
October 31, 2000

“Nobody knows what the new price of electricity will be,” said Peter Dyne, who is in charge of the energy committee for the Consumers’ Association of Canada. “So people should wait until the market opens.”

The new electricity market — slated to open sometime in 2001 — has led the way for a number of hydro retailers to sell electricity to a wider market.

The latest competitor to enter the fray is Toronto Hydro Energy Services Inc. — which recently sent letters across the 905 area to advertise its fixed one-year rate. The retail arm of Toronto Hydro promises a commodity rate of 5.65 cents per kilowatt hour.

Direct Energy Marketing Limited also has entered the local electricity retail market with a similar plan.

Consumers’ associations are convinced more offerings like these are coming to a neighbourhood near yours. But they also think that customers should be careful with those plans because it could be cheaper to stay with the local utility.

“I don’t think this is a market where you will see substantial savings by shopping around,” said Michael Janigan, executive director for the Public Interest Advocacy Centre in Ottawa. “It’s difficult to find out how there will be a cheaper supply.”

Under the old public system of selling electricity at cost only, municipal electric utilities such as Hamilton Hydro bought power produced by Ontario Hydro and distributed it. They billed their customers, kept some money to cover their costs, and passed the rest to Ontario Hydro.

Now the government is deregulating the industry by opening the power generation and sales markets to competition. Retailers can offer a competitive price, but consumers should know that they can still buy electricity from their utilities. In fact local utilities, such as Hamilton Hydro, become default providers for consumers who choose not to buy electricity from independent retailers. The utilities will buy the commodity at the best possible price, and sell it to customers at cost only.

“Essentially, the price is a pass-through,” Janigan said, adding that independent retailers would try to make a profit.

The utilities will buy most of their electricity on the unregulated market. As a result, the cost will be under market pressure and could be volatile.

Yet Ontario Power Generation, which still holds a near- monopoly over production, will sell most of the commodity on this market.

The government has legislated that the electricity Ontario Power Generation sells has to be priced on a yearly average of 3.8 cents per kilowatt hour for the next 48 months, until it sells part of its producing capacity to private generators.

Dyne explained the commodity price will be more than 3.8 cents per hour because the independent market operators will charge for their work. Moreover, the utilities will add a few cents on the commodity for metering and calculating how much hydro is needed at all times.

Tom Adams, executive director of Energy Probe, said other factors such as Ontario production shortfalls, high electricity prices from participating areas such as New York and Michigan or little investment in new electric generation could cause prices to increase even more.

Yet both Dyne and Adams think the price won’t exceed the current 4.5 cents per kilowatt hour. Adams said it’s now hard for consumers to find this price because it usually is bundled with the costs of distribution and transportation.

When deregulation kicks in, however, bills will have five components: the cost of the commodity, the costs of distribution, transportation, and taxes, and the payment on the old hydro debt.

Toronto Hydro still thinks the utilities cost will be higher than 4.5 cents, however, or even more than its own plan, for that matter. Yet to make sure that people don’t get locked into a contract they don’t like, the company offers the option of 30 days’ notice prior to cancellation at any time during the first year of the contract, at no cost.

“We know this market is complicated and that’s why we built the cancellation,” said Blair Peberdy, vice-president of corporate planning for Toronto Hydro. “It is risk-free for consumers. At any time, they can leave without penalty.”

 

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New Brunswick energy policy to address regional change

Posted on October 23, 2000 by Other News Sources

Cheryl Devoe Kim
Dow Jones Energy Service
October 23, 2000

A New Brunswick energy ministry secretariat is finalizing a comprehensive energy policy that will guide the government’s reaction to regional power market liberalization and the development of natural gas.

Led by the department of energy and mines’ assistant deputy minister Don Barnett, the secretariat will submit its policy paper by the end of the month, with public release of some of the contents expected in mid-November.

Industry observers are looking for some indication about the direction the province’s power industry will take. But the future of the key player in that market – New Brunswick Power Corp. (X.NBP), won’t be specifically addressed. Another committee is waiting in the wings to take on that task.

For NB Power’s part, it wants to see power-supply choice introduced at the wholesale level, which would affect three customers – the cities of Saint John and Edmunston and the village of Perth-Andover, said Stewart MacPherson, vice president of corporate planning.

On the retail side, NB Power wants the province to wait until other jurisdictions develop rules that deal with market power sufficiently before competition is introduced in New Brunswick, MacPherson said.

But pressure to introduce competition into the market is coming from the outside.

“The marketplace is really being restructured based on what’s going on around us,” Barnett said. “The question is how does NB Power function in that marketplace.”

Bureaucrats from several previous studies are recommending a “managed” transition into the new world, including gradual introduction of wholesale generation competition. They don’t want to repeat the mistakes made in other jurisdictions that have liberalized the power market.

New Brunswick is keeping a close eye on the New England market in particular, Barnett said.

“We’ve had a history of trade with New England. The market has been beneficial to the crown utility and its ratepayers as a result of playing in that market, and that market is changing,” Barnett said. U.S. Federal Energy Regulatory Commission requirements for reciprocity mean that some degree of liberalization is necessary to continue to reap the benefits of power exports, he said.

“I guess you have to take a look at yourself and see if you want to continue to play in that market. Are there things that one has to do with your own domestic system?”

The other significant agent of change in New Brunswick is natural gas. With the development of Sable Island natural gas and a pipeline into New Brunswick, opportunities for natural gas fired plants, and specifically cogeneration, are obvious for large power consumers.

“I really think that natural gas is playing a significant part in being able to develop the cogeneration potential in New Brunswick,” Barnett said.

Cogeneration is something that the province has thus far resisted, but NB Power is now scrambling to protect itself from the possibility of cogeneration, industry watchers say.

“They’ve been trying to lock customers into long-term deals,” said Dan Pastoric, senior vice-president, electricity for energy consultancy Energy Advantage Inc.

“I know that New Brunswick Power is running pretty scared. They’ve been trying to influence the government and they haven’t been successful,” Pastoric said.

But NB Power actually wants the province to allow its large industrial customer to develop cogeneration, Macpherson said.

“We have been recommending that our industrial customers be allowed to cogenerate by themselves,” NB Power’s MacPherson said. He acknowledged that the company has been discussing long-term contracts with customers, and said those customers have been very receptive.

One of the most obvious candidates for cogeneration in New Brunswick, refinery owner Irving Oil Ltd., welcomes the opportunity to generate power. “It would be a perfect fit for our refining business,” a company spokesman said. “It would also give us a level playing field to compete with our competitors throughout North America who are currently able to cogenerate power and steam.”

One industry observer isn’t expecting too much out of the new energy policy.

The policy paper will probably have vague comments about “continuing to review” options for power-wheeling, and continued talks with the Quebec and Nova Scotia governments, said Tom Adams, executive director of Energy Probe, a Toronto-based consumer and environmental think tank.

“They’ve shown no leadership whatsoever with NB power,” Adams said. He questioned the commitment of Premier Bernard Lord to effective address the challenges facing the province’s energy issue, since the premier has shown little interest in either energy or NB Power specifically.

“I’m expecting to be disappointed,” Adams said.

 

Posted in New Brunswick Power | Leave a comment