Crown Corporations -- Issue No. 16 -- Wednesday, June 11, 2003

2003 Legislative Session: 4th Session, 37th Parliament
SELECT STANDING COMMITTEE ON CROWN CORPORATIONS
MINUTES AND HANSARD

Present: Ken Stewart, MLA (Chair); Harry Bloy, MLA (Deputy Chair); Pat Bell, MLA; Susan Brice, MLA; Daniel Jarvis, MLA; John Les, MLA; Harold Long, MLA; Barry Penner, MLA; Rod Visser, MLA; Dr. John Wilson, MLA; Patrick Wong, MLA

Unavoidably Absent: Joy MacPhail, MLA

1. Pursuant to its terms of reference, the Committee reviewed and examined BC Hydro.

    Witnesses
    Larry Bell, Chair and Chief Executive Officer
    Bob Elton, Executive Vice President and Chief Financial Officer
    Stephen Bruyneel, Manager, Corporate Communications

2. The Committee recessed from 1:10 p.m. to 1:24 p.m.

3. The Committee met in camera to discuss the analysis of review of BC Hydro.

4. The Committee recessed from 1:35 p.m. to 1:40 p.m.

5. The Committee met in public session.

6. Discussed scheduling for next meetings, July 8 and July 21, 2003.

7. The Committee adjourned at 2:15 p.m. to the call of the Chair.

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE
ON CROWN CORPORATIONS



CONTENTS

		Page

Review of Crown Corporations: B.C. Hydro		231
	L. Bell B. Elton

Other Business		248

Chair:

* Ken Stewart (Maple Ridge–Pitt Meadows L)

Deputy Chair:

* Harry Bloy (Burquitlam L)

Members:

* Pat Bell (Prince George North L)
* Susan Brice (Saanich South L)
* Daniel Jarvis (North Vancouver–Seymour L)
* John Les (Chilliwack-Sumas L)
* Harold Long (Powell River–Sunshine Coast L)
* Barry Penner (Chilliwack-Kent L)
* Rod Visser (North Island L)
* John Wilson (Cariboo North L)
* Patrick Wong (Vancouver-Kensington L)
Joy MacPhail (Vancouver-Hastings NDP)

* denotes member present

Today in front of the Select Standing Committee on Crown Corporations we have B.C. Hydro. Just as a little bit of preliminary information, what we're going to be doing today, Larry…. We'll use first names here, if that's all right with you. We'll do introductions. My name is Ken Stewart. I'm the Chair. What we usually do is an hour presentation — I see that you've got a PowerPoint presentation, and we have a copy of the slides in front of us — or up to an hour, and then we have an hour for questions. You have two hours if you're…. We've never yet had a session where we've completed all the questions in the time, so if your presentation is shorter, that's great.

We are on Hansard, so everything we say today is recorded and will be up as public record within two days on the Web. Our report won't come out until the fall sitting. We're a legislative committee, and we report directly to the House, so it won't be coming out until that time. It will be confidential until that point.

There will be a series of questions that we'll have for you today at the end. If those questions aren't answered today and if there's more information that's needed, we just go through the Clerk's office, and they make sure that everyone gets copies. Also, as we develop our report, if there are other questions, we may be asking you further questions in writing later.

There were also two submissions that we received with questions from other groups. I will distribute those to you, and you can answer in written form back to us.

That's pretty much the overview. I'll start with some introductions. To my left, the Clerk of Committees.

L. Bell: We have a number of slides. There is a lot of information there. What we will try to do is highlight it. I'm aware of your request to keep our answers short in order that there can be more dialogue rather than less. We'll leave that to you to prompt us with other questions.

This provides the overview. We talk about our strategy, the external context of our business, the energy plan implementation — a very important initiative — and then some things about B.C. Hydro itself, which Mr. Elton will go over.

First of all, talking about the environment, there are a number of key things about our business that are unique. The first one is the obligation to serve. Where a business could normally have the option of having not enough, that is not an option for us. We, historically, have always looked to exceed the demand. Sometimes that's not appreciated in the sense of: was that a good business decision? We can't take the risk of not enough, so we always have a bias for too much.

We're a monopoly, but components of our business — and I'll show you that in our organizational chart — are not a monopoly. Clearly, in North America today generation is not a monopoly when we open the transmission lines.

An important lesson that's been learned from deregulation across North America is the difference between the value of electricity and its cost. We're regulated on a cost basis quite appropriately. We're a monopoly, and we need that kind of scrutiny and reminder that we have to be as productive as we possibly can.

The analysis of the impact of the brownouts in the Silicon Valley suggested that the value of electricity was roughly 100 times its cost in a normal situation. What we're talking about there is that if you bought electricity in normal times in California for $25 or $30 a gigawatt-hour, the absence of that electrical energy costs about $25,000 to $28,000, so it's value versus cost. We've always got to remind ourselves of that, because we come back to the obligation to serve. That's the kind of consequence of not having enough, and it's not enough in terms of two things. It's not enough energy — that is, over the year we deliver so many gigawatt-hours — but it's also the ability to meet peak demand.

We have two obligations: its capacity to meet that peak and to fulfil the obligation throughout a year.

We have a long asset-replacement cycle. Bob will show you later that some of our key assets are coming into the 35- and 40-year-old age range, and that has implications. Also related to that is a very long development cycle. If we were to, say, think about a hydro project today — you know, one that gets discussed as a Site C — we would estimate that it would take us somewhere between 11 and 12 years to deliver energy, with only about a three-year construction period. We've got a very long cycle. Of course, you then think about forecasts and how accurate you are, looking out ten to 12 years, and then you look at the obligation to serve — that is, you can't have not enough — and you can see the bias we have in our business towards being very, very conservative.

I guess the last one is that…. It seems obvious, but energy production impacts the environment in some way. We have Power Smart, of course, which is to consume less. That's the most benign source we have, but even there we're talking about products that have to be manufactured. We're talking about a whole series of trade-offs. There are no absolutes where we will not impact the environment. That just gives you some sense of some major characteristics of our business.

How are we organized? On the left you'll see engineering, 570 people. We contract for about 20 percent of our engineering, and we're looking to perhaps increase that to 30 to 35 percent. We need highly skilled specialists, but we're probably doing a little too much of what we would call commodity engineering. Field services is our linemen. Those are the people out in the…. And in there we have a construction workforce of about 400 people, highly specialized, who work in substations and so on and who have a very unique skill set.

In terms of our linemen, we have about 400, and we contract with private contractors for the equivalent of about another 200. Of course, that varies across the province. In Victoria, probably 60 percent of the business is contracted out. In a small interior town there would be no contractor, and we're 100 percent of that particular workforce.

Accenture Business Services, of course, is our back office, made up primarily of our IT function. Here there are some 1,600 people. This is a strategy, as you well know, to reduce our costs over the next ten years, to shift the risk of on-time, on-budget for major IT projects to Accenture.

It also is a growth strategy. We have 1.6 million customers. With new customer billing systems, if you want to be in the first quartile of costs, you probably need five million customers. What ABS is doing — and I am doing — is going out and selling our system to other utilities and, hopefully, building it up to that five million figure. So we have a growth model there.

Generation, approximately 700; transmission, 225 — we'll talk a little bit about BCTC and implementation there; distribution, 726 people. Then we have two subsidiaries: Powerex at 117 — who you know, of course, is our energy trading company and is very profitable and successful — and Powertech, which perhaps you're not too familiar with. That is our R and D subsidiary. About 35 to 40 percent of the revenue in any given year there is hydro. The rest is from customers around the world. This makes a profit of about $2 million a year — again, a successful enterprise.

What's our vision? We want to be a leading sustainable energy company in North America — hence, the emphasis on Power Smart. Of course, in a Kyoto world we have a very benign source of electrical energy in our hydro system.

Our total system, incidentally, represents a replacement value of about $32 billion, just to give you some context for what it would cost today. When you think about it, the development that took place as a result of the leadership of a Premier many years ago would have been proposing, in today's terms, about a $20 billion megaproject. It gives you some context in which that decision was made.

Our values. It's very important to align these with the views of our employees, and at every opportunity we remind ourselves that these are the guiding principles and values for all that we do.

Moving forward, then, there are three key priorities: the energy plan implementation, which calls for low rates and reliability; the long term — we have to look out 20 years — and that's our vision. We don't talk in terms of one and two years, because of that long cycle. We're looking to put together a plan that we will share with the public early next year in terms of a 20-year vision for energy in the province. I must say it is very fortuitous that we in this province have the opportunities that are here for us to realize that. What we want to do, of course, at all times is pursue operational excellence, so this has a value and quality proposition around reliability. Our benchmark is to be first quartile against other comparable utilities.

This is a map showing the electrical markets open to retail competition. What that essentially means is that a generator other than a utility can sell to an end-user. There are all sorts of different rules that would guide that.

What is being proposed in British Columbia in the energy policy is that this will be open to probably 100 customers. In fact, the 100 top customers in this province with multiple sites — so Canfor would be a customer with multiple sites — consume 70 percent of the energy in this province. When you want to induce efficiencies or when you want to give price signals, you don't need to give them to 1.6 million customers, because our average residential bill is $50 a month. What

is enormous for a Canfor or a Norske, in terms of a 5 or 10 percent improvement, to a residential customer…. You don't really want to say it's trivial, but it's not a significant amount of money. Of course, in areas where they deregulated the market, they just kind of…. That was lost. The transaction costs of people considering a variety of alternatives greatly exceeds their ability to realize any improvement. That was why a lot of these things were very flawed.

The scarce resource is transmission. Generation…. While there's a lot of debate and a lot of scrutiny, you can — and we do — build generating facilities, but we have not built transmission. We are living off a legacy, a legacy that's 20 or 30 years old in this province, and we're no different than any other area. This is going to be our challenge in the future. We obviously should be in a position — daily, monthly, annually — to move electrical energy from areas of surplus to areas of deficit, and for that you need a transmission system. That's our challenge out into the future.

B. Penner: Just for clarity, this slide doesn't show transmission and generation construction in British Columbia, does it? Or is this North America–wide?

L. Bell: It's North America–wide, and it is very similar. In fact, we would have less capital expenses on transmission, so that graph would be even more illustrative of the point.

Here you can see what has occurred in terms of price. You start over on the left. That's January '02. You can see that there continues to be price volatility. Of course, during the crisis of 2000 and 2001 prices reached $400 and, in some cases, spikes that were a multiple of that.

You can still see the volatility that's involved in this, and it very much tracks natural gas. This is the challenge for generation going forward. The decline rate in terms of natural gas is exceeding our ability to drill and realize new supplies, so any disruption — weather-related, etc. — sees price spikes. Because the predominant new development of generation is natural gas, natural gas sets the price on the margin. You can see that these things track very well. Of course, in a hydro system you have periods in which you have excess water or drought so that you get disconnects, but if you looked at it over the long run, these are closely correlated.

B. Penner: Again, just for the sake of people who might follow this through Hansard, you're referring to the North American market in terms of new generation being predominantly natural gas–fired.

B. Penner: And the slide you were talking about also showed the prices at the mid-Columbia.

L. Bell: Yes. That's a mid-C. That's a trading hub. It's a bilateral trade — that is, it's just buyers and sellers. You price it at that point, and then you pay for line losses and transmission costs from that point. That's how you calibrate your prices.

Climate change, of course, is something that we all are challenged by. The implementation of Kyoto is not completed at the federal level. I can just say that our emissions per gigawatt-hour, of course, are very low because we're a hydro system, and we are able to offset both the new generation at Island Co-gen in Campbell River and any future development on the Island with credits that we receive from our green energy call for IPP development and for our ramped-up Power Smart. So, in fact, we are able to have offsets against those emissions. Of course, we are challenged because while historically we have very low emission levels, at least part of the growth is going to be natural gas, so we'll probably see a disproportionate growth — not in absolute terms but in relative terms — to our emissions. The argument we are making is: we ought to get credit for what we've done historically. We are very low emitters, and there ought to be some threshold before certain provisions become mandatory in terms of offsets. In the meantime we are managing this through the next decade.

Energy plan implementation. Here are the objectives, and I'm sure you're very, very familiar with them: low rates; public ownership of B.C. Hydro — I don't know how I can be plainer than I have been in every public forum I'm in that the energy plan calls for public ownership of B.C. Hydro; secure, reliable supply obviously — reliability and the question of value versus cost, a very important factor; private sector opportunities.

Here we are getting a response from the private sector which exceeded our expectations and exceeds the energy we require. We need about 800 gigawatt-hours. In our last green energy call we had 5,000 gigawatt-hours proposed — just to give you some proportions. We have signed some 30 contracts, and we will sign another probably 20 early this fall. These are scattered all over the province — biomass…. We even have some with methane from municipal waste — one out here at the Hartland land dump. We have a wind project on Vancouver Island. Most of them are run-of-the-river, small streams hydro projects.

Regulatory schedule. We have an enormously busy schedule. It's busy for us; it's busy for BCUC. VIGP, Vancouver Island generation project — we'll talk a bit about the supply issues on Vancouver Island later. June 16, through the public hearings…. We've had some workshops, and we expect a decision some time in '03. We can answer some questions around Terasen and Norske if you wish. GSX — the review is completed, and the panel…. We expect a decision this fall.

The heritage contract and stepped rates — you can see the schedule there for the public hearings. In this case, BCUC is asked to report back to the government on its recommendations with respect to what we've submitted to them and the public debate that has taken place around heritage contracts and stepped rates, and

then the government will make its decision. This is essentially public policy, which is appropriately determined by government. That's been a very useful process. We've had some really good workshops. We've engaged various stakeholders. It's been a learning process for everybody, and I must say that the interaction has been constructive and helpful.

Revenue requirements — a decade without increases in rates. March, next spring, we will submit and we expect an interim increase to be awarded and a final determination in the fall of '04. It's a very heavy schedule. This, then, will put us in the position of having implemented energy policy and moved forward in terms of our revenue requirements. After that, there will probably be some rate design issues that will follow on the question of whether each individual class of customer is absorbing the appropriate burden.

Heritage assets. The average cost per gigawatt-hour of our heritage assets is $26. Our cost, if we were to put an inexpensive, most efficient gas plant in place with today's gas prices, is probably something like $70. We've got our average historic costs, and on the margin, as we must meet growth, it's something between two and three times the cost. Some of our assets produce electricity for $10 per gigawatt-hour.

What's the difference? The difference between the cost on the margin of new facilities and what our costs are…. There's a value there between $1 billion and $2 billion. That's the B.C. Hydro advantage. That's what provides our low-income, low-cost energy. This particular contract is to be put in place to preserve that historic asset.

There is one issue around that — and we have to work our way through it — inasmuch as some customers say: "You have an obligation to serve me. You are serving me. If I don't need this energy, maybe it's mine, and maybe I can sell it for that $70." Of course, that's not part of energy policy. It's a discussion that we have periodically in order to temper people's expectations around ownership.

Here's energy acquisition, customer-based generation, future calls, and green and alternative energy. That takes us well into that 50 percent clean target which is, I think, both an appropriate goal and one that is the envy of many, many utilities in North America.

The stepped rates. Here the concept is that the trailing rate, the rate you pay for that last increment of energy, ought to represent that $60 or $70 I talked about, in order that we induce people to conserve and induce them to invest in energy-efficient plants and motors and so on, using the appropriate price signal. To do this, of course, is revenue-neutral. This is not looking to increase revenue as a result of stepped rates but to provide an incentive for appropriate conservation.

BCTC. If you think of our business, in our existing structure it would be like a major airline owning the airport and scheduling all the other airlines onto the runway. We have put rules and protocols in place in order to provide fair access for generators in Alberta and for others — Cominco and Alcan, who are big B.C. producers, as well as smaller IPPs. But it's clear it requires a completely independent governance structure, and this is what we're doing.

The one point that's important to remember in all of this is that the transmission assets remain with B.C. Hydro. There is no transfer of assets. BCTC will have the right to use and to manage, but the assets remain with B.C. Hydro.

Having completed that, then, Bob, is this where we decided I'd hand it over to you?

B. Elton: Yeah. Before I talk about our performance last year and our expectations for the next few years, what I'd like to do is just spend a few minutes going through some contextual facts that we think will help you understand our business a bit better.

The first is to put in perspective the contribution Hydro makes to the province. As you can see there, it's in three components: taxes, which are really things like property taxes; water rental, which is variable, depending on how much electricity we generate; and then the dividend that flows to the province out of our net income. Over the last five years you can see it's been a reasonably stable return, somewhere between $700 million and $800 million. That's obviously a key issue we want to try and maintain.

While the overall return is stable, what is very variable is a key driver of our income, which is the water that comes into our system. You can see there are two things. The first is that the two left-hand columns show the very significant contribution made by the Peace River system and the upper Columbia system as a percentage of our total assets. The second is that you see the shaded portions show the typical range from year to year, which shows the difference between low and high water. That's very significant, because that can make a difference of a few hundred million dollars to our net income.

In terms of where our costs are made up, what our cost structure is, this chart shows what makes up a dollar that we collect. A key point I want to emphasize there, which echoes what Larry said earlier, is that about 41 cents relates to capital charges, which means depreciation, interest and so on. That means that the decisions made 20 or 30 years ago to build are what are having a big effect on our rates today. Of course, that also means that the decisions we make today in terms of capital investment will have a big impact on rates in the future. To put it in perspective, our capital spending for this year is around $745 million and will be for the next year or so, so it's a significant issue for us to focus on.

Another point to make is that while people tend to focus a lot on trade income — because I think people think it fluctuates more than it does, except for the period that Larry mentioned a couple of years ago in California when trade income was way up — it contributes a fairly steady probably about $100 million a year to our net income. We actually regard it as one of

the less volatile parts of our business because of the fairly conservative way in which we run it.

The map of our system really underlines a couple of things. The long distance between where the generators are and where the load is, is a significant issue, because it really affects reliability. I'll come to reliability later on.

The second thing is that because we're at the end of a system in the west, there are some fairly significant tie lines whereby electricity moves as it does in Alberta and in the Pacific Northwest and California. For example, at the moment we have restrictions on our ability to import cheap energy from Alberta. Those restrictions are caused by fairly straightforward planning assumptions that our transmission planners have to make, which in future BCTC would make. In the summer we expect we would be restricted fairly significantly from exporting through Washington and Oregon, and that will affect our ability to earn those trade revenues. As Larry was saying earlier, our ability to make sure in the long run that there is a transmission system that works not only in B.C. but also in the west generally is a key objective for us and a key reason for doing BCTC.

The third point that map shows is the thin line on the left-hand side that moves electricity to Vancouver Island, and I'll be coming to that in a few minutes in terms of the reasons why that particular line is causing us problems and we need to do something about that.

B. Elton: On the dotted lines? Yeah, it's transmission planners saying that we cannot let you export more than this amount physically at this particular time for a variety of reasons, either because there are outages in their system or for other reasons.

B. Elton: This chart Larry referred to earlier shows the age of assets, going from left to right, and shows what kinds of failures you get. The big line going down is around the 40- to 45-year line. It really says that for hydro facilities, once you get to that age, things start to go downhill fairly quickly from a cost point of view and from a failure point of view.

There are three arrows going down below that. The one on the left-hand side is our eight core facilities, so those are particularly the large assets in the Peace, the Columbia, Bridge River and so on.

B. Elton: It's the dams and the power stations, yeah. So it's the two together.

Their age is below 40 years, and at the moment those are in reasonably good shape. Obviously, as Larry said, they're beginning now to move towards that higher point in the curve. The smaller facilities are definitely fairly well beyond there, the point where they're at their most efficient and economic, so we've got some decisions to make in the next few years as to whether to invest in them to effectively reduce the age of them or whether to do other things. For example, we recently made a decision to decommission the Coursier Dam, which is basically for economic reasons.

K. Stewart (Chair): I'd just like to interject a comment. If we have comments from the members, please direct them to the Chair, because they won't get on Hansard if you don't. Also, it provides for a more orderly meeting, which we all want. They won't get in on Hansard if you just put them through at the side. Okay?

B. Elton: That chart showed that when physical assets get to age 40 to 45, they start to deteriorate. We don't make the same assumptions about people, of course, because when we get above the age of 45, we get wiser — right? That's the theory that Larry and I have anyway.

This chart shows the age of our workforce, and the red line there shows the percentage of our workforce in each line of business that is aged above 50. For example, in the field services group, which is the group on the right-hand side, more than half of the workforce is over 50 years old. That means that a very substantial percentage of them are coming up for retirement eligibility.

A fair amount of the work those people do is physically demanding, and a fair amount of it also requires a great deal of technical skills. Our field services group do some things technically in terms of, for example, bare-handed repairs or repairs to transmission lines using helicopters that are state of the art. So we have some issues in terms of being able to replace those people and finding people with the right training. Of course, it also gives us an opportunity, because anytime you've got a bunch of retirements coming up, it means you've got the chance to perhaps amend the cost structure and also to look for people with new and fresh skills.

One of the implications of that aging workforce is the effect it has on our pension costs. This chart shows that over the next few years, we see our pension costs increasing by about $50 million to $55 million a year. That really results from two things. We just had a valuation done of our pension fund assets, and like virtually every pension fund in North America, we've seen that the value of those assets has declined. We have to write that off over a ten-year period. Of course, that could change. Three years from now when we do another valuation, we'll obviously hope that the pension fund assets have recovered some of those losses.

The second thing that has happened to our pension fund — and this again, I think, is fairly common in North America — is that people are living longer and retiring earlier, which means that the liability increases because we're paying them their pension over a longer

period of time. The combination of the two results in that $50 million extra charge.

The next chart shows our salary scale compared with market. Basically, the message there is that at the top of the scale, our salaries are generally somewhat below the market, and that at the bottom of the scale they're somewhat above the market. We need to look at avoiding the flatness of that scale.

Larry, I think, has already referred to the shape of our costs. The left-hand side is the embedded cost of current generation, and every new resource acquisition that we have now will increase that overall cost. Every time we have to acquire new sources of energy, it will lead to upward pressure on rates. I think the next one we've already talked about in terms of where we're getting our energy from, so I'll pass by that one.

The pie chart showing the fixed-and-floating-price part of our portfolio…. What that means is that if you're reading in the newspaper about gas prices or electricity prices going up and are wondering if we're exposed to that, the answer is that we are, to that kind of percentage. We've fixed most of our costs, but there is still a fairly small percentage where we're exposed to higher gas and electricity prices.

I want to go through fairly quickly what our performance was in the last year. The first chart shows net income, which as you see was $350 million or so, which was on plan. We had a good year in terms of water, a good year in terms of market prices. Domestic demand was up somewhat. On the other hand, we has some of these other issues, like I mentioned, in terms of pension costs and high legal costs associated with California. I'll talk about California and Powerex in a moment.

The reliability Larry has mentioned several times. This chart goes through a five-year period and shows reliability by quarter. This is the average number of hours lost by any customer in a quarter. It works out to just less than four hours a year on average experienced by the average customer. Of course, there is no average customer. People tend to experience a lot less or a lot more than that. It shows that it's very seasonal, of course, because of winter. Frankly, the trend is up somewhat.

The next chart shows some of the costs of customer hours. While our reliability overall is decent, we are looking to desegregate that and look very closely at what is causing it. To the extent that it's adverse weather, there may not be much you can do about it, particularly given the length of our lines. To the extent that it's vegetation, there are certainly vegetation management programs that we have. We are desegregating that aggressively and looking at ways we can find of spending our money more wisely to reduce outages. I should say that customer satisfaction is still very high — I'll come to that — which suggests that our customers understand the reliability challenges we have.

In terms of VIGP and GSX, the issue there — and I already referred to the transmission line — is that we have an aging transmission connection to Vancouver Island. If you look at the next chart — I'll spend two or three minutes on this one — the bottom left shows the contribution to supply made by our HVDC cables, which is one of the ways in which we get electricity to Vancouver Island. That's the dark blue. We expect the dark blue will last no longer than 2007. It's possible that it may not last as long as that. This is something that we have many engineers thinking about all the time. We keep spending money to fix it, but when we can no longer rely on it, we will lose about 240 megawatts. We need something very significant and large to replace it.

At the top of that line in 2007, we see VIGP coming on. We need something of that size and, if you like, lumpiness to make sure that we can replace losing that amount of supply. Of course, we're going to be very interested in looking at other proposals for all kinds of smaller projects. Those are part of our plan and part of what's in there. But we need something large, significant and reliable because, as Larry said at the beginning, we can't be too late with this. We can't be two or three years too late to Vancouver Island, saying: "Well, we weren't sure when we would need it, and so we built it three years too late."

We're very obviously interested in the Norske and the Terasen proposals that you will have heard about. At our hearings next week we'll be saying that, provided we can get firm proposals from people that fit in with this time line, we're very interested in looking at them. We think the prudent thing for the BCUC to do is issue a CPCN for the Vancouver Island project and let us continue to entertain any other proposals that can meet this time line. The time line is the critical thing.

H. Long: Just on that power, are you referring to the Cheekye-Dunsmuir line? The underwater cable?

B. Elton: No. Well, it's not the Cheekye-Dunsmuir. It's an HVDC cable that goes from Delta.

B. Elton: Customer satisfaction. This year we've been calibrating our customer satisfaction ratings, looking more closely at them. Our overall rating is 93 percent, which means that's the percentage of people that were satisfied or very satisfied. With the tier 1 customers, which include those 100 customers Larry mentioned that consume 70 percent of the energy, our satisfaction rating was 99 percent. Frankly, we think it's very difficult to maintain those levels, but obviously we're very proud of them. We think that particularly high result with the tier 1 customers comes from Power Smart initiatives that, of course, those customers are very interested in working with us on.

In terms of safety, the trend there is very good both in terms of this measurement, which is frequency of accidents, and in terms of the severity of accidents that our workforce and others have experienced. We still want to see that trend line improve over the next two to three years so that we move into first quartile, which is where we are not yet.

This chart just shows our supply acquisition over the last few years. The blue lines are all IPPs. It just underlines the point that what we've been doing in the last ten years, really, is acquiring energy through IPPs rather than building it ourselves. That trend will obviously continue in the next few years.

In terms of Accenture, one of the things that we locked up this year, of course, was the outsourcing with Accenture. On this chart the yellow line there shows the costs to B.C. Hydro that we will get from Accenture for the services that were outsourced. The top two lines show our budget of what we thought our costs would be. The dotted one is without inflation; the red one is with inflation. The gap between those top lines and the bottom line is those savings you've heard about — the savings that we estimate to be $250 million over the next ten years. That's really why we're doing this.

It's been a couple of months, and so far the indications are good. There have been no real problems in terms of service, and so far we're feeling very good about the way this is going. Obviously, there's a lot of work to do in terms of implementing this and to make sure it works over the next few years.

I'll talk briefly about the California litigation. In the last 12 months there has not been, frankly, a great deal of progress made. There's been a lot of noise. I think we've just started to get more aggressive in our public relations efforts to make sure people understand that what we want here is an evidentiary hearing. What we're getting at the moment is a very politicized process. We believe we have done nothing wrong. We believe we've acted appropriately, in accordance with the rules of the market. This process that's described in this slide is costing us $20 million to $25 million a year in legal costs, and what we would like to do is get to an evidentiary hearing so that we can make some progress in proving our case.

The last point is credit issues. There's been a lot in the newspapers in the last year about those in the industry in terms of merchant energy companies. It's just to emphasize that our approach to credit in the trading business is very conservative. In the last 12 months we've had no credit losses, and whenever we've found that companies have been in trouble, we've found that a few months before that we had cut them off because we suspected they were going to get that way.

Briefly, then, to talk about what we expect over the next few years…. I'll spend a few minutes on rates. As Larry has referred to, we are expecting to be going to the BCUC with rate increases, and we will be doing that for next year, for the fiscal 2005. We haven't yet determined what we will be filing and asking for, for those expected increases. We said in our service plan that we think it might be in the order of 3 to 6½ percent over the next three years. This chart just shows that since the rate freeze was on ten years ago, CPI has basically added about 14 percent to costs. It just, I guess, links to the kind of rate increases that we've talked about in public.

To put it in perspective, as Larry said, for residential customers about $50 a month is the average bill. This chart shows a comparison of various cities. Vancouver is the third there in the list. This was a couple of years ago, and other people have had increases since then, so the kinds of increases we might be seeking will still leave us with very low rates compared with the rest of North America. The same is true for large industrial customers where, of course, the dollar effect is much greater. The chart has a similar picture.

The dotted line, which is a little bit hard to see, shows our tariff for each type of customer, and the blocks show what our costs are. Really, what this shows is that our commercial customers are subsidizing our residential customers and our large industrial customers. This is a fairly common picture across North America. It's something that the BCUC again will deal with through a rate design hearing. That will be after we have dealt with our revenue requirement hearing next year. There will, at some point, be a hearing that will address that. This kind of rate design issue is very much one that…. From our point of view, it's up to our customers to argue their case before BCUC.

In terms of the key performance measures I just talked about, for customer satisfaction, even though our achievement this year was 93 percent, we have not raised our expected level. We're saying that 84 percent remains a good level to achieve, particularly in light of all the changes we're going through, including the formation of BCTC and including the expected rate increase that we'll be seeking.

In terms of safety, we see ourselves making one more significant leap in the next year to get to first quartile performance, and then we expect to be stable after that.

Finally, I want to talk for a couple of minutes about net income. Our net income target for next year in our service plan is a $70 million loss. That reflects a number of things. It reflects expected problems with water. It also reflects some of the cost pressures I've already referred to. It reflects the fact that really, the rate freeze having gone on for ten years or so, it is time to seek rate increases.

Since that service plan was done, we have experienced some better water conditions, and so we're now expecting that that number, instead of being minus $70 million, will perhaps be $100 million higher or perhaps a little bit more. In other words, we do expect to make a profit next year.

The reference to our operational excellence strategy says that what we will be doing in the next year is focusing very hard on our costs. When we get to our revenue requirement hearing, the details of our costs will obviously be subject to great public scrutiny

through BCUC and through the regulatory process, and it's that process that will determine how much of our costs we can pass on to our customers in the form of rate increases versus how much of our costs will be absorbed by the shareholder.

Again, just to emphasize what Larry was saying earlier, we've got, really, three prongs in our approach. Restructuring the company to implement an energy plan. We think it will be probably another 12 months or so before we've really completed the large projects that we referred to earlier. The 20-year resource plan will be completed and will be public and will be the subject of public debate this year. We're obviously looking forward to that discussion with our customers.

Our focus, now that we have our company restructured, is very much on looking at those basic measurements of reliability, safety, customer satisfaction and costs, and on making sure that we can continue to deliver, as we have in the past, a stable financial return for the province while achieving low rates. Thank you.

K. Stewart (Chair): Larry, any comments you'd like to finish off before we get into questions?

K. Stewart (Chair): As I mentioned earlier, I have questions that were submitted here from two groups. I will just quickly read the questions in to the record, not the preamble that goes with them, and then I'll give them to you.

The first are from the independent power producers. Their first question is: why is B.C. Hydro stating that it will only buy one more allotment of 1,000 gigawatts per year next year for IPP power with no plans to buy any more until after 2010? Their second question is: why does B.C. Hydro not treat IPP projects the same way as its own projects with regard to future increases in government taxes and levies and fuel costs? The third question: why did B.C. Hydro, subsequent to the release of the province's new energy policy, select CPC's Brilliant project on its recent green-power-generation call from independent power producers?

The fourth question, which is to do with Burrard Thermal: in B.C. Hydro's resource plans, how much electricity is scheduled to come out of Burrard over the next one to ten years, and how do these volumes meet with the conditions of the 1995 GVRD air permit and the provincial government's promise to phase out the facilities? Why is B.C. Hydro not moving forward on phasing out Burrard and procuring power from cheaper, cleaner IPPs?

Fifth: on Powerex, what is BCH/Powerex doing to overcome the strong perception of power marketers with respect to Powerex's advantage of having access to storage and other services?

The next question: how many new IPPs have been developed that have been facilitated by Powerex? Are there contracts for over 10 megawatt- or 100 gigawatt-years? Are there any contracts over three years in duration? Did any new projects receive their financing based on long-term contracts with or facilitated by Powerex's effort?

There are two more questions. Why is BCH willing to pay $65 to $130/MWh for VIGP but will only pay $58…

K. Stewart (Chair): Megawatt-hours. Okay. There we go. We're getting this down.

Why has B.C. Hydro not immediately issued an RFP for IPP power on Vancouver Island without the $55/MWh cap?

The last question is: will B.C. Hydro be developing another gas plant on Vancouver Island? Sorry, there is one final question. When was the last time B.C. Hydro seriously looked at the cost of fixing the underwater high-voltage transmission cables? At what capital cost would the underwater-cable-fixing solution be less expensive that the recently revealed higher VIGP/GSX costs?

I'll submit these to you. You can just return those in writing through the Clerk.

K. Stewart (Chair): There's another series of questions here that we've received. This is from…. Just by note of the Clerk, I want to make this really clear. These are questions that we received from outside — they're not our questions — from other witnesses. We just want to be clear that you're aware of that.

This one came from Aquila, which is a company out of Alberta. They have quite a series of questions here, so I'll just submit them to you without reading through them. I think that would be a little redundant at this point. From Aquila, there are approximately ten questions. I'll just submit them to you. I think that'll serve.

L. Bell: Ken, just for the information of the people here, they also do serve the Kootenays — although it's a small part of their Canadian holdings — and they are up for sale at this point in time. Crédit Suisse has been in touch with us with respect to our interest for some of these assets.

K. Stewart (Chair): I appreciate that. Just to let you know with regard to this, Larry, what we're trying to do is leave this process as open as we can. We'll just hand those on. Again, if you can put those in writing back to the Clerk, we'd appreciate that. We'll use it for our consideration in our final report.

K. Stewart (Chair): There's a process we use for questions. We basically have one question each and go

around until we run out of time. What we try and do is ensure that members have their most pressing question first.

I'll take the prerogative of asking the first question. Yes, the Chair does get a question. It's one that I'm sure you're aware of. I'd just like to refer to two documents. One is the shareholder's letter of expectations on page 3: "Specific to B.C. Hydro" — and it's pretty clear here — "the shareholder will…maintain its commitment that the core generation, transmission and distribution assets of B.C. Hydro will remain under public ownership." That's the one part.

The second part came from your presentation today, and that was with regard to the low rates and public ownership of B.C. Hydro. That was page 13 or slide 13 of your presentation today. Could you comment on that? I know it's one area that we hear all the time. I think clarification would certainly be helpful on the record.

L. Bell: I guess the best way to be clear is to be short. These assets are not for sale. I'm prepared to elaborate, but because the question arises in so many different ways, one has to be as plain as that: they are not for sale.

K. Stewart (Chair): So to be very clear, you're clearly following the direction under that shareholder's letter and under the mandate you've been given from the government in that process.

P. Wong: On page 22 of your presentation here you said that allowable net income is 17 cents out of every dollar of revenue. Does it mean that 17 percent net income is the regulated or expected return? How does it measure up with other organizations in the industry?

L. Bell: Our equity is defined. We earn a rate of return on our equity, and that has been defined by the regulator and by the province in its instructions and how that is to be defined. It is not comparable to a private sector company. We have less equity as a Crown corporation. It's around 22 percent on the book value of our assets. We're allowed to earn a rate of return which is directly comparable to the before-tax rate of return earned by B.C. Gas. It varies with respect to the rulings that will be made from time to time with respect to B.C. Gas.

P. Wong: Supplementary is that I understand B.C. Hydro does not pay any corporation tax to the provincial and federal…. If you bring that B.C. Transmission Corporation out, would that be taxable or not, and what would be the expected rate of return?

L. Bell: It will be the same rate of return, and the tax regime will not change.

D. Jarvis: I have one that I'll start off with, Larry. Some of these I'll end up giving you in writing later on. Going back to the IPP section of it. This might be somewhat facetious, but I noticed that in October of '91 the IPP contract was 15 pages.

D. Jarvis: Yeah, the standard electricity purchase contract and the IPPs. Then in October 2001 it went up to 40 pages. In March 2003 it's now gone up to 80 pages. In 2004 and 2005, is it going up any further?

I wanted to read you a bit here and get a quick interpretation. I want to know what the cost is. Is it internal legal costs? Do you have your own lawyers inside that are drawing these up, or are they going outside? What kind of costs are they looking at? I'll leave it with you, because you may not be able to answer right now.

The last question — not the last question but part of that original question…. In the last contract, under the annual capacity for factoring LDs, I don't understand it. It's such a difficult thing. I wonder if anyone understands it, even in the electricity business. For example, you say: "Annual contracted electricity means electricity expressed in MWh, calculated as the product of the average annual contracted capacity for the relevant year, as stated in part 1 of appendix 2, and the number of hours in that year, other than all force majeure hours and all transmission constraints." It goes on and on and on. This is one line, and it's really confusing. I was wondering if you could have someone interpret it for me later on.

L. Bell: I'd be pleased to do that. Just a general observation that these have become more complex because we are relying more and more on these as sources of energy, and at greater proportion, to serve our customers. We have to be much more definitive. If it's 1 or 2 percent of our supply, that could be absorbed into a large system. Going forward, of course, this is going to be — other than Power Smart, Resource Smart — the supply. Therefore, we need to be much more precise. It is a language all of its own, and we will interpret it for you and provide you a written response.

K. Stewart (Chair): Okay. With that one, we'll just add it to the list, and it can come back through to the Clerk.

B. Penner: My question relates, in some way, to page 28 of the PowerPoint presentation we saw. This is

a slide contrasting the various costs of different sources of electricity, existing versus new generation. On that slide you have new least-cost supply estimated to be about $55 per megawatt-hour, up to a range of perhaps…. It looks like it's approaching $70 a megawatt-hour. It seems to be on par with the possible new Site C dam, according to that slide on page 28 of the handout we have.

Given that and given some of the comments Alan Greenspan made yesterday while he was testifying before the U.S. Congress about his long-term concern about the rising price of natural gas, is B.C. Hydro reconsidering what it considers to be its new least-cost supply measurement? I know that's used as a benchmark against which B.C. Hydro considers the price it's willing to pay to other providers of electricity. Given that there seems to be some concern, certainly at the highest levels in the United States, that in the long term natural gas prices are going to be higher than what we've come to expect, that may — I would suggest — affect the new least-cost supply numbers used by B.C. Hydro, and it may be time to reconsider that benchmark.

I'm asking this question in the context of Vancouver Island, because I understand that's where the most pressing need is. I also know that a number of possible alternatives include wind generation, and they're telling us that at $55 per MWh, if that's all B.C. Hydro is willing to pay, they may well not be economically viable. The benchmark that's being used to limit that price to $55 per MWh may no longer be accurate or justifiable, given what's happening to long-term natural gas prices.

L. Bell: Yes. We share that concern. We engage independent consultants and ask them to give us their views in the long-run cost of natural gas. As you well know, we will require both LNG and Arctic gas to supplement the existing traditional supplies in North America. It is the view of the industry that these new supplies will be realized, so that long-run cost continues to be between $3.50 and $4. We see some difficult times in the short run as these facilities are built. That's the view of professionals who appraise these markets.

Do we need to think about, as a strategy, avoiding as much as possible taking fuel risk in our portfolio? Absolutely. In this 20-year plan you will see us proposing Site C as a resource alternative that ought to be considered, because you can fix very, very small variable costs, so you basically fix your fuel cost.

L. Bell: Into the long term. We think that today, and in a Kyoto world, we really have to seriously re-engage our stakeholders in that kind of discussion, and we will, in our integrated energy plan.

The next call we will go out for…. You referenced specifically the independent power producers. Our job is to acquire the most reliable, least-costly energy source available. We'll go out on a competitive basis, and while we have put a cap on these calls to date, our plan is not to cap them into the future. We'll let them compete. Our experience has been that we're getting something like $53 as a cost being bid in.

We had to start this process. We didn't want people, for example, to be spending a lot of money in proposing $90 energy to us and then wondering why the couple of hundred thousand dollars they spent on their proposal did not materialize in any net result for them. So the future calls will not have a price cap on them, and there will simply be locational credits. As you know, we provide a locational credit for Vancouver Island because of the scarcity, but beyond that, we will see what the market provides us. We've got enough evidence to suggest that the private sector is now prepared to propose more than we require.

P. Bell: I'd like to pursue the Accenture deal just a bit. My understanding of the deal was that the savings to be generated per year were a reflection of Accenture going out and acquiring additional contracts from other utilities to supply back-office services or billing services — that type of thing. I wonder if you can give us an update on where that currently stands and if there are some target dates, if there are currently negotiations going on or if they've made any progress on that matter.

L. Bell: The answer is yes. Obviously, the names of the companies need to be confidential. I can say there is a utility in western Canada that will be announced within two or three weeks. The deal has been done; it's a question of their existing supplier. They're trying to work some things out. There is a potential for a major corporation in another industry in B.C., and an MOU has been signed there. It's a confidential MOU, but I would think that in two or three months that will be public.

There is a small amount of front-end work being done with a utility out of Louisiana. In fact, six employees of ours who transferred to Accenture were working on the front end of that contract on April 1 when we cut over.

We have had a serious inquiry from Australia, and I spent a good deal of time with the CEO. When I was in Toronto last week, I met with a major government institution that is looking to reduce its back-office costs, and they're going to bring their executive team out in early September to talk to us. I'm encouraged, but I'm sort of saying: "Let's get an announcement here. Let's really ink something." I just hope that happens in the next couple of weeks, but I'm very encouraged.

P. Bell: Great. If I may, as a supplemental to that, could you give us an indication of the impact on the employment ratio within Accenture? Would that end up as a reflection of increased employment over time?

Obviously, you can't reveal any numbers; that wouldn't be appropriate here. But is that the sense of where these deals are going?

L. Bell: Yes. First and foremost, of course, as Accenture realizes more productivity, we'll want to absorb those people who become redundant in that productivity as they drive for productivity. Secondly, it is a growth model. There's no question about that.

P. Bell: Finally, if I may, with the Accenture model, can you describe the board of directors and who we have on the board of directors?

L. Bell: Yes. There's myself and Bob Elton and Jay Grewal from B.C. Hydro, and there are four individuals from Accenture. We become the board of this joint venture. They also are putting together an independent board of leading business people as an advisory board, and that will be announced — well, I would hope….

They have been recruited, and they will provide independent advice to the joint venture and to Accenture.

K. Stewart (Chair): Pat, did that round out the question for you about that?

J. Les: The situation on Vancouver Island is, I guess, accurately described as being somewhat tenuous. Maybe others share this with me, but I'm not exactly clear as to where B.C. Hydro is going with that. I hear a lot of discussion and a lot of fuss and noise about cables and pipelines from here back to the mainland, and I hear some discussion about RFPs in the private sector to address the Island's future needs.

Can you sort out for me exactly where you're going with that? I mean, it seems to me there are some pretty good potential sources of electrical power on the Island. How are you balancing that with the applications you have before BCUC and perpetuating and perhaps expanding some of those infrastructures across the Georgia Strait? If you could spend a few minutes doing that, it would certainly enlighten me.

L. Bell: First of all, as Bob referenced, there is the DC cable from the fifties. There is an end of life. It has seismic challenges. Pieces of it need to be replaced and are being replaced. We are now shoring it up just in order to get by this critical period. But it is 240 megawatts. That's the immediate challenge.

In terms of natural gas on the Island, the existing system does not provide sufficient gas as it is configured today for those critical cold periods. Remember, this is capacity. This is to meet the peak today. Island Co-gen would not be able to run flat out on the Island, because we would not have sufficient gas.

There are alternatives. You can put more compression on that gas pipeline. Very recently Terasen has proposed, as well, an LNG facility on the Island. This is about a billion cubic feet. It requires about 40 acres. What that does, of course, is take gas during the low-demand periods and compress it and provide it for the peak. Is that a solution that is more competitive than the one we've proposed, which is the Georgia Strait crossing, which is just a pipeline that would supplement the gas supply on the Island? That's the debate.

Our view is, to the degree to which we understand the Terasen proposal — because remember, we've been at the pipeline for five years, and they have just made their proposal in the last two or three months — we still think that GSX is the appropriate way to solve the gas supply issue on the Island.

With respect to electricity itself in the capacity, we think that a combined-cycle gas plant, which would consume that increment of gas supply as well as allow for peaking for Island co-gen, is the appropriate solution. There we have a range of alternatives that one can look at. First and foremost, there are some who would say you can take that DC cable and kind of patch it. The answer to that is yes. We have our experts on this who tell us that it's at its end of life. Again, we have industrial reliability standards, our industry standards, which we must adhere to. It does not meet those standards even if we patch it. Could it extend a couple of years? Probably, but we're not in the probably business. We have to have certainty with respect to supply.

That's one debate. The other debate is: should you string new cables? But then that says you need the gas plant built somewhere else. How much sense does that make? Why would you locate it somewhere else when you take it to the load centre in order to reduce the transmission costs?

What are the other alternatives? Norske proposed in December, and subsequently modified its proposal, that it would put a variety of cogeneration plants in place. This has some attraction. The attraction is that Norske is the biggest customer on the Island. Typically, what we would do in a utility if we found ourselves with insufficient capacity is what we call "load shed." We'd drop customers so we can keep that supply-demand balance. In fact, what we would do would be to drop our industrial customers.

My discussion with Norske said: "Really, we are entertaining this because you are a perfect hedge. If you don't deliver on the cogeneration, you will be the first person who's impacted." We are still asking them questions about how well-developed their proposals are, because we still have a responsibility not to be cavalier with respect to the services to Norske certainly. That will be part of our discussion at the hearings.

We think it's an obligation on our part to point out to them that perhaps they've got a lot more work to do

to have some confidence in deliverability of these co-gen projects. If they're prepared to take all of that risk, it may well be that the Utilities Commission will say: "Fine. That's the cheapest option." We just need to see how they're going to finance it and what kind of payments they require from us and so on, and that's not clear. So that's a real possibility in my mind. These would be not only biomass- but gas-driven as well. Then you back into the gas supply issue, and it's not clear what we need to do there.

Above and beyond that, we think, of course, that there is going to be growing demand on Vancouver Island, so we have put a special effort into Power Smart on Vancouver Island. We'll continue to do it, and we'll launch it again this fall. I hope all of you have your compact fluorescent bulbs and all our giveaways and so on. We have provided a premium for IPPs on the Island to induce supply here, and we have some, but it's not anywhere near the 240 megawatts we will lose with the DC line.

B. Elton: It's just that in the green call, we got seven Island proposals on the shortlist. They add up to about 28 to 60 megawatts, which is great. But again, as Larry says, it doesn't get us to the 240. There are, as you say, lots of sources, and we're exploring them all.

L. Bell: Just a point of clarification. I will need to check this, but there's a $5 premium. I'll need to….

K. Stewart (Chair): If you get the clarification, just get it to us later — no problem.

H. Long: A two-in-one question — very, very short. On the Cheekye-Dunsmuir line, which crosses, of course, Texada Island and so on, what's the life of that existing line, and how much power does that supply to the Island? I know they had some major problems there last winter when some of the lines were almost totally out in the snowsheds.

As well, I want to go back and pursue Norske and their proposals to possibly put in co-gen. What consideration is given to industries like Norske who, on the world market today for pulp and paper, are having a major problem that impacts on many small communities — Powell River, Campbell River and many of the other small communities? In the case of the B.C. Utilities Commission, it would actually look at the effects of the cogeneration and how that affects their ability to compete in world markets. There are so many jobs involved at all these community levels within their pulp mills and sawmills and whatever. What consideration is given to Hydro? How do they look at the favourability on, for instance, Norske, which is a good example that you brought up, and how that's going to impact? Of course, one person could be cheaper, but if Norske couldn't compete because this is part of their major plan and we lose another 3,000 or 4,000 jobs, we won't need much power in the future.

K. Stewart (Chair): Just before you answer that, if I could clarify. You know, we have had B.C. Utilities before us. I would expect your answer to reflect B.C. Hydro, not what you may think B.C. Utilities would do, given the question is pretty broad.

On the line, there are two 500-kV lines. One went out with a mudslide about three years ago, and then we had the snow this year. What we say is that that's the first contingency in our planning criteria. It goes out, and you can still serve load. Guess what. The second line went out. It was some trees that got on the line, shorted it out, and there's your second contingency gone. Of course, that's all an integral part of our planning standards. That line is through very tough terrain. We have beefed up the towers as a result of our experiences with both snow and mudslides. We think that line probably has a life of 20, 30 or 40 years, but we will be constantly challenged, because we're going through very, very tough terrain.

With respect to co-gen and Norske, maybe it would be useful for me to use an example of the Weyerhaeuser arrangement we made in Kamloops. That's the kind of model we're negotiating with another major company and what we hope would be the model, if we can come to terms with Norske, that would form the principles of the deal.

We look at this as acquiring energy. Then we say to ourselves: "What does it cost?" In the Weyerhaeuser deal, we said: "We're prepared to prepay for energy in order to allow you to put the capital into a co-gen facility, but we're not going to offer you an infinite rate of return. Let's have a discussion around what would be an internal rate of return which is a reasonable rate." It's around 20 percent. I think in that case it was slightly under 20 percent, and we obtained the energy for under 1½ cents. It's a win-win. They reduce their cost structure. We get inexpensive energy, and we don't have fuel risks, as Barry mentioned, by going and generating with natural gas, because they're using biomass in this case and very little gas. It's a win-win, and it does improve the viability of these industrial plants.

We are, in fact, going to announce soon another arrangement like that. We think that over and above Norske, there are probably four or five others that are going to make economic sense throughout the province, and we're going to pursue those.

S. Brice: Thanks, Larry. Following up on this same theme, with the GSX project about to get its full public

scrutiny, and with the Norske options and certainly what I've heard of Crofton and Elk Falls and the Port Alberni location, what role can that potential project play in the decision of the hearings regarding the GSX? Will that probable or possible option play into the mix, or does one have to get the negative before the others can go ahead?

L. Bell: No, GSX is the pipeline. VIGP — all our acronyms, Susan; I'm sorry — is the gas plant. That's what's going before the Utilities Commission. The GSX…. We've had our hearings before the National Energy Board, and they'll have a decision this fall for us.

With respect to VIGP and the hearings at BCUC, we have already had workshops, and both Terasen and Norske have participated. We think it's better to have a public airing of the advantages and disadvantages of these particular proposals. Our view would be that we should get an approval on VIGP, and one of two things could happen. We could go ahead with building that and serve future load by incrementally moving on the Norske co-gen projects over a five- or six-year period, which would then meet growth and demand on the Island, or we could…. If we were satisfied that they could deliver on a timely basis, it could delay VIGP. We would have approval for it, but it would be delayed.

H. Bloy (Deputy Chair): I'm not sure if you answered part of this, but in your presentation you talked about people providing electricity — wanting to buy electricity from you at a low rate and sell it. Is this the Weyerhaeuser deal you're talking about, where you're saying it's restricted? Is it part of your conditions of contract with your customer base that the electricity's not for resale? Are we interfering in the private market of entrepreneurship?

L. Bell: With the obligation to serve goes the franchise, if you like. It's very traditional in utilities that you do not resell. If you want to be a utility, you go to BCUC and apply to be a utility, and then you can resell. That is just not normal practice anywhere in North America.

H. Bloy (Deputy Chair): But that's what people were trying to do. Is that what you're saying?

L. Bell: Yeah. It would be this. Let me give you an extreme example. I won't name names, but let's say you've got an old plant, and it's limping along. You have consumed 1,000 gigawatt-hours a year, and you're buying it from us for 2.6 cents. So you say: "Well, I'm going to shut this plant down, and I'm going to sell this energy — which I consider to be a right — to somebody else at the market price." The policy is clear that that goes back in the pool for the benefit of those who require it for running enterprises.

K. Stewart (Chair): As we move on with the questions, one of our major roles is to sort of benchmark your performance — where you do your comparatives when you're doing your evaluation — and then we look at that. We've talked a lot of generalities about what B.C. Hydro is doing and your policy. I'd like to direct a little more now into your performance measures.

One of the things I'll just touch on is your customer satisfaction measurement. Looking at that as an example, what types of comparables do you do to other industries in the same business? When you look at other utilities in other provinces, other jurisdictions, how do you compare and rate yourselves? What indicators do you use for, as an example, customer satisfaction? Do you just have your own in-house thing and it shows that you're at 93 percent? Where are you getting that?

L. Bell: The first level of comparability is measuring ourselves against other utilities. We can provide you with that information.

L. Bell: We are very pleased with how we compare. The other is a little more problematic because you need standardized questions and so on, but just the absolute level of satisfaction we have and the fact that it's going in the right direction provides us with the comfort that we are doing the right kinds of things, particularly with that major customer list. We're astounded that it was that high. We really were astounded.

We have benchmarks throughout the organization, and we would be very pleased to provide that for you. We have the standard ones that you would expect in the call centre — for example, that you answer after 15 seconds 85 percent of the time and only lose 1 percent of the calls.

We have more difficult ones where we are measuring the amount of maintenance dollars that we need to put into a large dam facility and its reliability — like, when we call on it, how many times we have to say: "Well, gee. I'm sorry. It's not quite ready to operate." We have those as well. Those are a little more difficult, but we have some comparabilities.

I can say on that one that we need to improve some things there. We're not in the first quartile where we

want to be; we're in the second quartile. It's not bad, but it could improve. We think it's probably because we are coming on that bathtub curve towards the end, and we need to shift our maintenance programs and, in fact, even our capital replacement programs so that we maintain a greater reliability and reduce maintenance expenditures. We will provide those to you, Ken.

K. Stewart (Chair): Similarly with your area of billing and your arrangement with Accenture, the types of measurements you use to say: "Here's where we were, and this is how we're showing we're getting the $25 million a year." That is the type of information that helps us judge your performance. If you can get us that, that would be helpful.

P. Wong: I understand that there's a letter of expectation between the Minister of Energy and Mines and B.C. Hydro. B.C. Hydro is accountable for managing its business in a commercial manner. In other words, B.C. Hydro is responsible to ensure that its assets are not liabilities managed with certain risk management. It has a very important impact on the heritage contract rate, which is expected to change at the end of the year or maybe early next year. I'm not talking about an uncontrollable factor such as the level of the snowpack. I'm concerned about the controllable factors.

The first one I'm concerned about is the rate stabilization account. I would like to know what amount is in that account and what's the rate of return and who is managing it. The benefit of Accenture — would the benefit be transferred to the RSA account so that consumers will benefit as a result of it? In the year 2002 we transferred $145 million from that account to stabilize the rate.

The second factor that I would like to know about is the legal situation of the $100 million collection from Alcan. The third thing is about the pension liabilities. Last year we allocated $28 million to pension costs. In the coming year we're going to increase 250 percent to $72 million. Obviously, I understand that's the stock devaluation. Does it mean that we haven't had adequate protection in the actuarial calculation in the previous five or ten years, so we have to make such a big adjustment — a fairly abrupt adjustment — in the coming five years?

K. Stewart (Chair): Larry, if I could, it seems like there are quite a few questions there. If you can pick one you'd like to answer now, you can maybe get the rest to us in writing, because I want to give the other members a chance for a second question.

The Alcan $100 million (U.S.). This was a contract that resulted from the Kemano 2 settlement with the province. It was a contract that had some value. Alcan sold it, with our consent, to Enron some years ago, but we required that Alcan maintain its corporate guarantee on its obligations to us. Obviously, Enron was unable to meet its obligations, so we made a claim on Alcan. The provisions of the contract called for arbitration, and the arbitrator awarded us $100 million (U.S.). This matter will be under appeal, of course, and probably will not see resolution for perhaps 18 months.

R. Visser: In your service plan, page 28, your strategies for field services training…. By '05-06 you're going to be training 129 trainees. According to your presentation, 52 percent of the field services employees are over 50. By '06-07, based on your pension benefit analysis, you're probably going to be having some significant shortages of people. Are your strategies there adequate over the next three years to meet that future demand for field services people?

L. Bell: We believe so. One of the constraints which we have, of course, is that when we bring apprentices in, we need enough journeymen and enough locations in which to train them. We're pressing the envelope with that a bit.

We're very pleased, though, that in the college system they've now put a program together. While we used to bring the apprentice in and do all the training and absorb all the costs, there are now young people who are going to Kwantlen College and paying $8,000 to take preapprenticeship courses and then applying for jobs with us. This provides a much higher success rate, because this is a screening process. In addition, it provides a pool for the contractors to draw on. Remember, they're about one-third of the technical people we use in our system.

If we had an onslaught of retirements, would we have some difficulty? Yes, we would. Our experience has been that somewhere around 25 to 30 percent of those eligible for retirement actually do retire, so it's kind of a balancing act. Believe me, we do a lot of analysis to try and figure out when people are going to actually leave. In B.C. Hydro, interestingly enough, we do not have a compulsory retirement age. We have a person in our warehouse who's 72 years old. I wish I was in as good shape as he is. There are some people who love the job. While those poles seem to get higher and higher every year, they still want to stay there. It's our judgment. I think the answer is yes, but we keep our fingers crossed. If we had something that induced a lot of people to retire, we probably would end up with them working for contractors, taking their pension, so we probably could bridge the gap.

D. Jarvis: Larry, I've got some concerns with regard to Powerex — the moneys coming in from California and the trading we're doing and what FERC is trying to do. They, broadly speaking, are saying that Powerex is involved in the energy problems with California and Enron and all the rest of it. Nowadays everything is

sort of electronically recorded, and trades are heavily documented. So when it finally comes before the courts, I'm concerned about what the exposure of British Columbia is going to be and what this could mean to us. Also, FERC is deciding what to do about the long-term contracts and whether we have any long-term contracts ourselves. Are we entering a defence for the moneys that California still owes us? Were the bonuses that were paid to our traders on those trades during that period of time paid out on the moneys we haven't received?

L. Bell: I can give you some quick answers. The bonuses were paid, but remember, we made about $1.4 billion during that period of time.

L. Bell: Oh yes. That's what we got. That's over and above. We did not book the $260 million (U.S.) that is owed to us. We did not book it. Just to put the performance into perspective, we have no long-term contracts. We did not enter into long-term contracts in January-February of 2001.

Are we concerned? I think Bob very correctly characterized this as much a political process as a legal process. We find it very, very difficult to deal with. We have submitted hundreds of thousands of pages of evidence. We have examined all the tapes — because all our traders are taped, as you would well expect — and we have not found one example of a trade which we could not defend as being an appropriate commercial transaction. That's why we want to have an evidentiary hearing where it is based on law.

I am going on Monday, and I have a meeting with the chairman of the Federal Energy Regulatory Commission. I am going to make that request of him. You may have seen in the newspapers, of course, that we've asked our ambassador to intervene on our behalf — and the U.S. Ambassador to Canada and so on.

I'm very pleased that the chairman has agreed to meet with me, because I can't plead our case. I can only plead for process. I'm cautiously optimistic that his agreement to meet with me means that he sees some merit to what we're requesting.

B. Penner: Yes. Thank you, Mr. Chair. I'll try and package these up. First, a very quick short snapper I think you've addressed to the Chair, but just to get it in a concise form: is B.C. Hydro in any way, shape or form for sale?

B. Penner: One of the things I was interested in hearing you say earlier was about the fact that 70 percent of the electricity in British Columbia is consumed by 100 or so large industrial users. My grade 11 math tells me that means only about 30 percent, then, is actually consumed by residential consumers in the province. Is that correct?

L. Bell: And small commercial. There would be some large commercial with multiple sites in that top 100.

B. Penner: Right. Nevertheless, it remains a goal of mine — and I think it might be a worthy goal of B.C. Hydro — to continue to remind British Columbians that electricity is not something that should be taken for granted. I'd like to salute B.C. Hydro for the information centre they have at the Stave Lake powerhouse near Maple Ridge, a wonderful facility that I had a chance to take in on Sunday along with my nieces and nephews.

I commend it to everyone. I am disappointed, however, that not many people in the lower mainland know it's there. I realize it opened just last year. For example, at the Hoover Dam in Nevada, I'm told they get 5,000 visitors through their information centre per day, paying $10 (U.S.) per person, and that the number of people is consistent, day in and day out, virtually every day of the year.

That's a much larger dam, but the information centre serves the same kind of purpose that I think the Stave Lake information centre could, which is to remind British Columbians where electricity comes from and to not take it for granted.

In that vein, is B.C. Hydro willing to consider a number of things that we sometimes hear talked about such as net metering for residential or commercial users, where people would then be encouraged to generate some of their electricity at home, although it might be more expensive? If they're willing to install, for example, a solar panel on their roof, is B.C. Hydro willing to consider stepped rates at the residential level to promote load-shifting, so people might use their dishwasher or dryer in the evening when B.C. Hydro is able to buy cheaper electricity than it can during the daytime? Is B.C. Hydro considering offering green power at the residential-retail level to help facilitate B.C. Hydro acquire a possibly higher-priced renewable such as wind generation?

I know that in the United States some public utilities offer green-tagged electricity at the retail level, and it might carry a premium in price of perhaps 2 cents a kilowatt or $20 per megawatt-hour. I think those are three imaginative ways we could help instil in the public mind-set that electricity is not free and get people thinking more consciously about their usage, about whether or not to leave that light switch on or use their dishwasher in the middle of the daytime or perhaps at night.

K. Stewart (Chair): Larry, you can pick one. I know that's a really good commercial by Barry, and I'm sure you'll be hiring him in the future to do your commer-

cials, but if you have some quick responses to that…. At least we've got those questions on the record, and you can follow up with him. I would like to get to the others. If you've got a couple of quick responses, that's great, and if not…. It's up to you.

L. Bell: Sure. The net metering proposal will be at BCUC within weeks. It is prepared, and we're ready to submit it. There are some questions around the cost of metering and so on, which impacts.

The shift of time-of-day use doesn't hold as much value to our system as it does to thermal systems. We're a hydro system, and we can store our water or use it. We need to make that first step with the industrials. Let's learn. Let's see what happens.

On green power, the answer is yes. And for Stave Lake, thank you very much for the commercial, and I'm delighted you're wearing our T-shirt.

K. Stewart (Chair): As I move around the table, as we're nearing the end, Pat, if you have a question to ask and if you have other questions you'd like to put on the record, do it at this time. Then Larry can pick the most concise answer he can get out of the questions and do it. I'll go around and let everyone on this side do it; then I'll come back here just for written questions that you haven't got to yet. Go ahead, Pat.

P. Bell: Just a last question, Larry. I note in your presentation on page 24 the concern that some of your facilities are starting to wear out and will require some investment, and yet in your plan I don't see any significant strategies that would indicate either upcoming investments and/or expenditures as they relate to improving those facilities over time. I'm just wondering if you can kind of put together the connection between your service plan and your comments as they relate to deteriorating facilities for me and help me understand that.

L. Bell: Perhaps it's not as clear in the service plan as it could be, but we can certainly clarify it in a written response to you. We have a focus on business-sustaining capital. We will, in fact…. Historically, people who underspent their capital budgets maybe didn't get an "Attaboy," but at least they didn't get into trouble like they would if they overspent. Today we have to spend. A good example of that is our underground cables in Vancouver. They're coming to an end, and we've had some potential accidents around explosions and so on and so forth. That five-year plan of replacing those things has to be done.

We have a business-sustaining capital program clearly identified, and we'll provide you that information.

J. Wilson: Just a very short question, Larry, on IPPs. I think we have a huge potential in this province. What is the carrying capacity of our transmission lines in comparison to what we produce through B.C. Hydro? I mean, what would be the volume over and above what B.C. Hydro produces and uses on these lines to accommodate IPPs? Does B.C. Hydro get first shot at using their electricity to supply the market where that capacity, say, was filled? Will the IPPs have to market their own power rather than sell it to Hydro? If they have a contract in place, will that take effect over…? If the carrying capacity, say, maxed out, would Hydro have to accept that loss? Will IPPs be under any type of control through the Utilities Commission or through international markets as to where they can sell and what they can charge?

L. Bell: Any IPP that's serving domestic load has an equal access onto our grid. We do very complex studies in order to ensure that wherever they're being located, it can be accommodated and that the physics are right and that the load capacity of a particular line they're hooking up to is adequate. On a domestic side, it's a technical study, and then that's not their concern anymore.

Can they market their own power? Yes, they can, but we'll need some BCTC changes, and they'll have to get up and running and get the tariff in place and so on. Over the next 18 months that will occur.

What about regulation? With an IPP, unless it's the size of a Cominco or something, it's very, very difficult to sell your own power. You've got credit; you've got booking transmissions. These are all very highly skilled jobs and very tricky. You'd have to go to an intermediary. That's the practicality of it all. You can go to Powerex and make a deal, or TransAlta or TransCanada Pipelines. Those people have the skills.

J. Les: Bob talked earlier about the pensions and their sustainability. This, of course, isn't something that's unique to B.C. Hydro.

J. Les: In the last couple of years there have been sorry experiences worldwide around pension sustainability. On page 26 you've tracked future benefit costs. I wonder whether you have something that indicates what your experience has been in the last several years in terms of how much ground you've gained or lost and what you expect that to be in years going forward so that, as the Chairman said earlier, we've got something to help us monitor that situation.

L. Bell: Yes. This is obviously very significant. Our operating, management and maintenance costs are $525 million. You can see that this is pretty significant in that context. We have the same concern as most people with defined benefit plans, because not only did we have the losses…. We're satisfied with our managers. I mean, compared to the market and benchmarks and so on, they did an okay job, but these are liabilities

now. There have been changes in the accounting treatment., as you know, in the amortization rules — right, Bob?

L. Bell: So that's part of the explanation for that. We could provide you with a fuller answer on that in writing.

J. Les: Just as an editorial comment to that, I noticed very recently that in Europe they're starting to put off people's access to retirement benefits until age 67. I suspect we may see more of that in years to come.

S. Brice: Larry, if I could just go back again to Vancouver Island. It seems to me that there are three groups. There is the general public, who basically flip on their lights, don't give a thought about it, expect it to be there and assume it will always be there. There are industry, all the municipalities and certainly your staff, who have convinced people that we're at a precarious point. In fact, industry is saying they're holding off making decisions based on future energy.

Then we've got people who are kind of running around with all kinds of numbers and being critical of B.C. Hydro's projections, particularly for load and peak, and claim that over the last decade, say, B.C. Hydro has historically projected higher than the reality. Could you give me some idea of how confident you are with the capability of your people to accurately project the requirements?

L. Bell: Well, Susan, you know the facetious answer is that if you want to get a forecast right, make many forecasts. But there's something I mentioned earlier, and perhaps you weren't here — that we cannot take the risk of not enough. We can absorb too much. Because of our obligation to serve, our forecasts will always be biased upward.

Do we get it right all the time? No. I think the test for us is: do we get it right so that people's requirements are served, so that when they turn that light on, it works? To the degree to which we overbuild to excess, we ought to be criticized, but if we're two or three years out…. We're a long-cycle business. I mean, we've been at it since 1995, on the VIGP. That's eight years. The difficulty of responding to requirements just makes you very conservative, and I think it's appropriate.

K. Stewart (Chair): At this point if anyone has any outstanding questions, if you can make them very short, we'll ask them now and just put them on record. If not, you can send them in if you think about something later. Are there any questions someone would like to put to Larry right now?

Go ahead, Patrick, and then Barry. Just short, concise questions. No answers needed.

P. Wong: You have very high customer satisfaction: an average of 93 percent. Also, for account manager…. For transactions surveyed, you've got 97 percent satisfied customers. In the contract with Accenture, is there any clause or anything there in case there's a drop in customer satisfaction? Is there any penalty element included?

B. Penner: Larry, you've spoken a number of times about B.C. Hydro's obligation to serve and to continue to acquire enough generation to meet customers' needs in British Columbia. That hasn't changed — I don't think. Even with the introduction of IPPs selling power to B.C. Hydro, the Crown corporation still retains the obligation to meet the needs of the province by acquiring sufficient supplies however they choose to acquire it.

But isn't it true — at least, I've heard it alleged — that B.C. Hydro has gone from basing their capability of supplying the province from an assumption of low-water years to average-water years? If so, that would seem to suggest a fairly significant shift and a move away from a very conservative approach to a somewhat less conservative approach. Is there any truth to that allegation?

L. Bell: The short answer is: I'm not sure it's a shift. When our demand was such that we were serving the load somewhere between the low and the average water, that distinction didn't matter. Now we need average water. High water would eliminate our gas production. As our demand shifts up, we don't have that cushion we had before, but we do make our calculations on average water. We do think we need to re-examine our policy with respect to acquiring more energy, and we are going to be doing that.

My personal view is that we need to be a little more aggressive in terms of IPPs over the next couple of years to provide ourselves with a cushion, particularly if we can get the ones that are green and the ones that have no fuel risk in them. Today, as Bob pointed out to you, we have 7 percent of our supply that is subject to market forces, either gas prices or electric prices, and perhaps that's not an appropriate ratio.

D. Jarvis: Following the likes of Cohen, Barrett and the Zalm, who say we're going to sell Hydro and domestic prices are going up, you say you're preserving heritage prices. But I don't think you're explaining that aspect very well in the sense that prices are going to go up because they have to go up, because of our infrastructure and all the rest of it. Is there any estimate as to what is the expected increase? I mean, this could be a natural cost. Just because they've been frozen for years doesn't mean they're going to stay frozen for years too.

L. Bell: Right. We put in our service plan this year an expectation that the annual increase, starting in April of next year, would be in the order of 3 percent to 6.5 percent.

K. Stewart (Chair): I just have one further comment on that. That was with your using the consumer price index. It's the same comment I made to the Utilities Commission — that everyone seems to use the consumer price index when they can't justify the price increase on their own, and so they go to there. I would just trust, when you're using your comparables and telling us what it is that's happening in your industry, that you're specific to that and that if you have needs for increases, they're well documented so we can use those for our benchmarks and not just "the consumer price index went up, so obviously we've got to go up the three points."

L. Bell: Absolutely. For instance, interest rates have an enormous impact on us. It was there for illustrative purposes only, Ken.

P. Bell: You don't have to answer it now, Larry, but I'd just be interested in getting something on your plans around Site C at some point.

K. Stewart (Chair): Thank you very much, Larry and group. We appreciate your coming today. Again, there's some information that we asked for. If you could send it to us electronically, it's a lot easier for us to distribute that way.

K. Stewart (Chair): The second thing, as I mentioned earlier, is that we will not be reporting out until the fall session. We appreciate it, and if you want, in a few days you can go over Hansard if you want some clarification about what the questions were, etc. Feel free to go through Audrey at the Clerk's office. She's very helpful. Thanks again.

K. Stewart (Chair): Can I have a motion to move in camera so that we can discuss the reports?

K. Stewart (Chair): Okay, we're back on the air. A couple of cleanup issues. We have no more meetings scheduled, at this point, after today. We will schedule some now, though. That's the next topic before we get too excited.

The time lines in July. I noticed there was one date in July when we all will be back here. I believe it's around the 22nd. Is there a time, while we have everyone here, that's convenient prior to that date of, I believe, July 22? Can everyone grab their calendars and have a quick look? We're to be here on July 22.

K. Stewart (Chair): Yes. It's Tuesday, July 22. Would it be the preference of the group to meet on Monday the 21st or Wednesday the 23rd?

K. Stewart (Chair): Maybe, depending on the time of the caucus meeting…. Pat, do you know the time?

I just wanted to advise the Chair that there is a small-scale salvage meeting, which would have not that many — perhaps three — members from this committee on the Wednesday. So from the perspective of the members that are on the small-scale salvage committee, Monday would be a preferable day to Wednesday.

J. Wilson: If we have a Monday meeting, it means I usually have to leave Sunday to get here.

K. Stewart (Chair): Okay. Let's tentatively schedule it for the 21st, and we'll get back to you with regard to times. Is there a desire to meet prior to that to have a meeting? It would be nice if there were a day early in July — maybe around the 9th.

P. Bell: On the 9th, again, is an all-day small-scale salvage meeting. But there's only Member Wilson and myself….

K. Stewart (Chair): Yeah. We can come in on the 8th, say. Let's tentatively schedule one for July 8 too, and we'll just take it from there. We'll get back to the members and see if it works. Okay, we'll take those dates and try and work around them.

K. Stewart (Chair): All of us. Harry, Susan and I will discuss that and see who's available.

B. Penner: I was just going to ask: which is the next Crown corporation that we'll be reviewing?

K. Stewart (Chair): If you've got a suggestion, throw it out here now. We had a few from last time. If there's any preference, let us know. Think about it between today and tomorrow, and let us know tomorrow, and we'll start working on it.

B. Penner: Would it make any sense, given that we've just done the BCUC and now B.C. Hydro, to invite Columbia Power Corporation?

K. Stewart (Chair): If you have any other suggestions, please get them to Harry, Susan or me by tomorrow, and we'll meet tomorrow and try and come up with one. Tentatively, we've got a date on the 8th and the 21st.

Any further comments for today? Again, I encourage you to get your reports in to Audrey as quickly as possible.

In addition to providing transcripts on the Internet, Hansard Services publishes transcripts in print and broadcasts Chamber debates on television.


Witnesses:	Larry Bell (CEO, B.C. Hydro) Bob Elton (B.C. Hydro) Stephen Bruyneel (B.C. Hydro)

Committee Staff:	Audrey Chan (Committee Research Analyst)

REPORT OF PROCEEDINGS (Hansard)

SELECT STANDING COMMITTEE ON CROWN CORPORATIONS

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE
ON CROWN CORPORATIONS