Crown Corporations — Issue No. 10 — Tuesday, November 13, 2007 (HTML)

2007 Legislative Session: Third Session, 38th Parliament
SELECT STANDING COMMITTEE ON CROWN CORPORATIONS
MINUTES AND HANSARD

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE ON
CROWN CORPORATIONS



CONTENTS

		Page

Columbia Power Corporation		131
	B. Chuddy L. Doney B. Duncan R. Smith

Other Business		148

Chair:	* John Rustad (Prince George–Omineca L)
Deputy Chair:	Guy Gentner (Delta North NDP)
Members:	* Iain Black (Port Moody–Westwood L) * Ron Cantelon (Nanaimo-Parksville L) * Joan McIntyre (West Vancouver–Garibaldi L) * Dennis MacKay (Bulkley Valley–Stikine L) John Yap (Richmond–Steveston L) * Corky Evans (Nelson-Creston NDP) * John Horgan (Malahat–Juan de Fuca NDP) * Chuck Puchmayr (New Westminster NDP) * denotes member present


Witnesses:	Barry Chuddy (President and CEO, Columbia Power Corporation) Lee Doney (Columbia Power Corporation) Bruce Duncan (Columbia Power Corporation) Randy Smith (Columbia Power Corporation)

J. Rustad (Chair): We'll call this meeting to order. My name is John Rustad. I'm the MLA for Prince George–Omineca and Chair of the Select Standing Committee on Crown Corporations.

Today we have the pleasure to review the service plan and annual report of the Columbia Power Corporation. But I'd like to start off with introductions of my fellow MLAs. I'll start with Joan, down at the end.

J. McIntyre: I'm Joan McIntyre, and I'm the MLA for West Vancouver–Garibaldi, which includes the Sea to Sky corridor.

D. MacKay: Dennis MacKay, the MLA for Bulkley Valley–Stikine, which is in northwestern British Columbia.

I. Black: I'm Iain Black, the MLA for Port Moody–Westwood, which is ten minutes further away from here than I thought it was. My apologies.

C. Puchmayr: I'm Chuck Puchmayr, MLA for New Westminster. We have our own power utility, and we benefit from this greatly.

J. Rustad (Chair): With us also is Craig James, who is the Clerk of Committees, and Jonathan Fershau, who is our committee research analyst.

B. Chuddy: Thank you, Mr. Chair, committee members. I'd like to start by introducing the group that has joined me today. To my left is Lee Doney, the chairman of the board of directors of Columbia Power Corporation. To my right is Randall Smith, who is the chief financial officer of Columbia Power. To his immediate right is Bruce Duncan, the vice-president, strategic planning and regulatory.

My name is Barry Chuddy, and as of June 1 of this year I was appointed the president and CEO of Columbia Power. Also joining us, although not forming part of our official delegation, is the president and chief executive officer of our sister company, Columbia Basin Trust, or CBT as we affectionately refer to them. He's also with us today in the gallery.

This is the first time we've come before the committee, so I thought I'd begin by providing a brief history of Columbia Power for the members, who may not be as familiar with us. Columbia Power was created in '94 under the Company Act, which is now the Business Corporations Act. We were put in place to acquire the expansion rights at Cominco, which is now Teck Cominco Metals Ltd. — the Brilliant dam on the Kootenay River, the Waneta dam on the Pend-d'Oreille River. In 1996 Columbia Power also purchased the Brilliant dam from Cominco.

CPC is an agent of the Crown, and the relationship between Columbia Power as agent and the province as principal is set out in an agency agreement.

In 1995 the Legislature enacted the Columbia Basin Trust Act, creating CBT, and the province entered into a financial agreement with CBT for the development of the Brilliant expansion, the Waneta expansion projects and the Arrow Lakes Generating Station, which is adjacent to B.C. Hydro's Keenleyside dam on the Columbia River, via joint ventures between Columbia Power and CBT.

Columbia Power is the manager of the CPC-CBT power project joint ventures. We develop, own and operate power projects using the commercial discipline of earning an acceptable rate of return and raising long-term debt from commercial markets on the strength of our projects without government debt guarantees, much like independent power producers.

The biggest difference between Columbia Power and IPPs is that we are owned by the province. We pay grants in lieu of taxes, and we have certain other restrictions on us.

Mr. Chair, if it's acceptable to the committee, I won't read all of the slides. I assume the committee has seen them, so my intention would be, in a presentation to you, to summarize what's in the slides, if I may.

B. Chuddy: Slide 2 is a slide setting out in a summary fashion how we are organized and our ownership structure. As you will note, all of our undertakings are done on a 50-50 partnership with our sister company, Columbia Basin Trust. Each of our projects is owned by a project company, creating a ring fence that limits liability across projects.

You will note that in early 2005 our mandate was confirmed and our governance was altered by the creation of an external, skills-based board of directors. Our board is government-appointed and has six members: our chair Lee Doney, to my left, who is with us; Jane Fleming; Art Willms; Charles Reid; Josh Smienk; and Ron Miles. I should also add that Messrs. Smienk and Miles have been nominated by CBT, all in accordance with our governance documents.

Our board has three committees: a finance and audit committee chaired by Charles Reid; a human resources and governance committee chaired by Jane Fleming; and a newly created project committee, which Josh Smienk chairs.

In addition to board oversight, all material decisions of Columbia Power require prior Treasury Board approval, pursuant to the agency agreement between Columbia Power and the province.

The shareholder's letter of expectations — signed by the Minister of Energy, Mines and Petroleum Resources and our chair, Mr. Doney — directed CPC to carry on operations consistent with the framework established by the shareholder; to find a president, which was done on June 1 of this year; to work with Columbia Basin Trust to ensure we achieve efficiencies; and to bring forward a development plan for our Waneta expansion project.

With respect to milestones, some of our recent milestones include our Waneta expansion project. I'm pleased to report, Mr. Chair, that today we received the provincial environmental permit and that we're close to receiving the federal environmental permit, so it's a rather significant milestone for Columbia Power.

I was brought on board as president and CEO in June, and pursuant to a government directive, we recently began paying grants in lieu of property taxes on our Arrow Lakes and Brilliant expansion projects. After many challenges, our Brilliant expansion project went into commercial operation on September 7.

We announced the closure of our Victoria office on September 26 and are currently in the midst of both a corporate restructuring and a hiring program in the Kootenays. We are expecting to present to our board of directors a decision to move forward on a request for proposals for the Waneta expansion project within the next couple of months, which will give us more certainty on the capital cost of that plan.

Let me move to the business model, if I may, which is slide 6. There are several slides to be taken together here. We emulate the business model used by many independent power producers, where we contract out the design, construction and operation of our projects. This allows us to keep a core group of highly trained professionals to oversee and conduct due diligence on the various elements of our business.

Project planning, design, financing, construction, operation and power sales involve private sector firms wholly or in part. Columbia Power follows a private-public partnership model, or a P3 model, for the design, construction and operation of the joint-venture power projects. This allows Columbia Power to properly allocate and manage risks and realize innovation and efficiency through competition. The model has five distinct components: design, evaluate, build, operate and, finally, manage projects.

Slides 7 and 8 again get a little busy, so I'll summarize, recognizing that the committee may have questions later. These two slides provide a broad overview of the five components of Columbia Power's business, and under each component we show the key activities, projects, outcomes and results.

Outcomes includes things like environmental permits; signed contracts with clear expectations and an appropriate allocation of risk between Columbia Power and the contractor who is building the project; effective project development with projects completed to specifications; reliable, cost-effective plant operations; ongoing environmental benefits; effective financial planning with sufficient cash flow to service debt, fund capital requirements and generate an increasing stream of dividends over time; and providing shareholder value.

Again, I won't get into detail on the business model. I'll leave it to questions.

Moving to slides 9 and 10, our performance plan summary. Slide 9 provides an overview of Columbia Power's performance plan that links individual performance measures with Columbia Power goals and objectives across the five major components of our business. Performance measures provide a scorecard for measuring the achievement of CPC's mandate and our vision.

Several of the performance measures are fairly standard items used to evaluate effective financial planning and financial health — items such as bond ratings; debt service; debt service coverage ratios; and return on equity, of course, being a very fundamental one.

Other performance measures evaluate effective project development; building on time and on budget; and reliable plant operations, such as plant outage ratios and environmental compliance. These measures are typical of the construction and electric industries.

Slide 11 — let me step you through some of the items noted on this slide. As far as effective project development, the most significant variation relates to the commercial in-service date of the Brilliant expansion project. This plant is almost exactly a year late as a result of a number of issues that my management team and I are currently sorting out with the contractor.

The Waneta expansion continues to progress, albeit slower than expected. A number of changes have resulted in delay, but the bottom line is that I'm confident we currently have a solid development plan established — with the largest variables in that plan, in my opinion, being certainty as to the power purchaser and the capital cost of the project.

Regarding variance from budget, to date we're in good shape, but I must point out that we're sorting out two legal issues that, until resolved, create an ongoing uncertainty regarding financial outcomes.

Regarding project bond ratings, we continue to be rated very high. As a result of the quality projects in our portfolio, I don't see any material changes.

The last key performance measure is return on equity. It requires some explanation. The relatively low value of CPC equity returns reflects the fact that Columbia Power uses equity to finance project construction. The Brilliant expansion construction, largely financed with equity, is an example.

Once a project is commercial and the construction risk has been eliminated, Columbia Power goes to the commercial bond market to raise project financing, freeing up equity to be used in the development of Columbia Power's next project. Over time, with the

completion of Columbia Power's project portfolio, we will have spread our equity over more revenue-generating projects, and the overall return on equity will rise.

Most electric power companies of our size would focus on a capital structure in the area of 70 percent debt and 30 percent equity. As we set out in later slides, it is our intention to move towards that financial structure with the development of our Waneta expansion project. Having said that, recoveries as a part of the channel recovery claim for our Arrow Lakes project have put us ahead of our 2006-2007 target.

Let me review the significant changes and assumptions. We're presently involved in finalizing the details of an insurance claim with FM Global relating to the Arrow Lakes plant channel issue that occurred a short time ago. The matter is in the hands of subrogation counsel, and Columbia Power is working closely with counsel and the contractor, Peter Kiewit and Sons, to finalize the matter.

As I mentioned earlier, the Brilliant expansion is about a year late, and I'm happy to report that pursuant to raising the level of attention to the CEOs of the consortium of contractors and equipment suppliers, the plant is now commercial as of September 7, 2007. After going commercial, however, the plant was down for a further month as a result of DFO issues, for which we are presently sorting out a number of details.

The Waneta expansion has been delayed in permitting and also to ensure that we issue an RFP to contractors that reflects Columbia Power's need to ensure we have a reasonable capital cost with an appropriate sharing of risk. Given changes in the major-construction market, we're taking the time to do that properly.

Again, the primary issues are the final price of the Waneta expansion energy and capacity relative to other supply options in B.C., and to ensure that we have a proper plan to sell this output. Those items are occupying a fair bit of time, effort and consideration within CPC. I'll make the point that as you look at and evaluate the capital cost of Waneta, you need to evaluate it against other options in the province, recognizing that the absolute value is important, as is the relative value.

The issuance of long-term debt in the commercial bond market to finance the construction of the Waneta expansion will restructure Columbia Power financially. I see that happening sometime in fiscal 2008-2009. We're also modifying the financial model for Waneta to incorporate the terms and results of the power call that B.C. Hydro issued in 2006 and to deal with the changing dynamic of the Canadian–U.S. dollar exchange rates.

Finally, with the endorsement of our board and pursuant to discussions with the shareholder, we are closing our Victoria office, consolidating functions within our Castlegar office and restructuring the corporation to better position us for the future.

If I can turn to slide 13 now. As noted, our capital and borrowing requirements relate largely to our Waneta expansion project. I'm happy to report that consistent with the report of our financial adviser and our discussion with a number of commercial lenders, in which I've been personally and directly involved, and thanks to the strength of our balance sheet and the strong nature of our project portfolio, we have the capacity to attract a significant amount of debt to allow us to finance Waneta. There continues to be much work to finalize this, but again the good news is that to date, all of the indicators are positive. Assuming that we continue to make solid progress on Waneta expansion, I expect this to happen in the next fiscal year.

With respect to government objectives, slide 14, let me review our progress in relation to the various stated government objectives, the first being economic benefits and job creation. Some of the highlights of CPC's projects in this regard are $90 million in net income for the province and CBT over the horizon of our service plan; the payment of $41 million of grants in lieu of taxes and water rentals; and subject to the requisite reviews and approvals, the Waneta expansion will deliver about 680 person-years of direct employment and a huge amount of direct and indirect income, with local procurement in the Kootenays of over $25 million. In short, I think Columbia Power is delivering a significant amount of value to the province, the community and the project stakeholders.

In the category of self-sufficiency, sustainable environment and climate action, I think we have another good-news story. With the electricity that our projects provide to British Columbia, we are a big part of the drive towards electricity self-sufficiency in this province, and it's being done using energy that would otherwise be wasted over existing dams.

Also, with respect to reductions in greenhouse gases and a move towards reducing those impacts on climate change, our projects are displacing over 1.75 million tonnes per year of CO₂ which would be generated had B.C. imported that power from coal-fired generation. Once our Waneta expansion comes on line, we expect to be helping the climate change initiative further by bringing that CO₂ reduction down by another half-million tonnes per year, for a total reduction of 2.3 million tonnes in greenhouse gas levels. We are also doing this in a way that is beneficial to fish, by reducing total dissolved gas levels in the water by significant reductions in water being spilled over existing dams.

Let me move to first nations. We are working very closely with first nations communities, both in the project development and construction phases of our projects. In development, we conduct appropriate studies and work very closely at agreements with those nations to ensure that we properly manage the development process. We regularly consult with those communities relating to our project's impact, are involved in training programs and initiate community benefit and sponsorship programs. In short, our developments are done responsibly, and in this area we work very closely with our sister company, Columbia Basin Trust.

If I can turn to the specific projects now and just do a quick review for the committee. I think you may find some of the points interesting. The projects that we'll

review would be the Arrow Lakes Generating Station and transmission line, the Brilliant plant and terminal station, the Brilliant expansion project and, of course, Waneta.

Although our projects are structured in single-purpose companies, each is highly integrated into the overall Columbia-Kootenay system in terms of both river operations and the integrated electrical generation and transmission systems. We work very closely with B.C. Hydro, FortisBC and Teck Cominco in the development and operation of these facilities. With respect to system operations and power entitlements, we are also working very closely with B.C. Hydro. FortisBC and B.C. Hydro are our primary purchasers of power, and FortisBC operates and maintains our facilities.

All of our projects have long-term power purchase contracts with B.C. companies, including FortisBC, B.C. Hydro and Powerex, which is a subsidiary of B.C. Hydro. We are presently working to ensure similar long-term power purchase arrangements are in place for our Waneta expansion project and are negotiating an entitlement agreement for that project with B.C. Hydro.

We are involved in various regulatory proceedings. We typically intervene to ensure Columbia Power's projects are appropriately taken into account in assessing B.C.'s resource options and to assist FortisBC and B.C. Hydro as purchasers of our power. While Columbia Power is not regulated, the purchasers of our power need to justify their power purchase decisions in regulatory hearings, and we regularly support them in that regard.

The point of slide 20 is simply to illustrate graphically the relatively stable nature of the electricity output of our various projects. This basically maps all of the energy output of our projects together. Although it may look a little busy, if you stay at the top lines, it's basically showing that we produce a lot of power throughout the year, not just in June and July, which is often a characteristic of run-of-the-river projects.

We're providing an important source of reliable capacity as well as green electricity to British Columbia year-round. I should add, however, that as B.C.'s needs for electricity continue to grow in the summer months, Columbia Power's plants are there and respond by providing additional power at that time, as is demonstrated by the graph.

I'll just quickly summarize the direct benefits of some of our projects. A quick review of the value that Arrow Lakes brings is that we spent $270 million in capital costs, with about 85 percent of the 750 person-years of construction employment coming from local hires. We spent over $20 million locally and produced enough energy to power about 77,000 homes.

Let me turn to Brilliant dam. The existing 125-megawatt plant was bought for $130 million, and pursuant to an upgrade project that we spent about $100 million on, it is now capable of producing 145 megawatts. This plant produces enough energy to power about 98,000 homes.

With a construction cost of about $26 million, this substation — the Brilliant terminal station — adds to the overall stability and reliability of the bulk power system in British Columbia. Linking our projects into the grids of B.C. Hydro, FortisBC and Teck Cominco adds to that overall stability.

Our Brilliant expansion project has a capital cost in the order of $205 million and started construction in 2003 — as I mentioned earlier, recently going commercial. As I also mentioned earlier, as a result of some of the white sturgeon issues, it was started after being down for about a month after going commercial and at last report is running fine.

We spent over $45 million locally. Of the 450 person-years of direct construction employment, again, over 85 percent of those people were hired locally. This plant produces enough energy to power about 47,000 homes.

Again, you've heard a fair bit about Waneta. We are permitting this plant at up to 435 megawatts and are hoping to make it a construction commitment sometime in the next ten to 18 months. This project will result in a significant amount of money being spent over the next four years. Once built, this EcoLogo-certifiable project will produce enough power to produce 72,000 homes. Again, as I mentioned earlier, it was just today that we received confirmation of our environmental permit from the provincial entity overseeing that.

In aggregate, Columbia Power's projects, with Waneta, produce enough green energy to produce power to satisfy the needs of about 300,000 homes with electricity. This chart shows which communities the labour resources for our Waneta project will come from and the number of people expected on site during various elements of the construction period.

Slide 27, "Key issues." I think, generally, Columbia Power is a good-news story. We do have a few issues that we're presently dealing with, and I'll summarize them.

The two major legal issues we're dealing with are the channel repair costs for Arrow Lakes and contractors' claims for our Brilliant expansion project. Completing deficiencies at Brilliant expansion is to some extent tied to the resolution of the claims by the contractor and will also be impacted by our ability to deal with some of the DFO issues.

Waneta is a significant item we're dealing with — the two key items being a power purchase contract at suitable rates and an appropriate capital cost.

Finally, an item which I spend a lot of my time on is all of the organizational items we're working on throughout Columbia Power, including the shutdown of our Victoria office, corporate restructuring and all that that entails.

We thought we'd end the presentation on a high note. Our last slide speaks to the many awards and items of recognition we have received at Columbia Power. I won't read them all, but thanks in large measure to the dedication and resourcefulness of the only 44 people at Columbia Power, we have achieved, in my opinion, many great things.

Hydroelectric projects are some of the most difficult projects to move forward, and I feel proud to be part of a company that brought several significant projects on

stream over the past few years. This is no small feat, and the staff and management of Columbia Power, in my opinion, are to be congratulated.

I would add that we have people attending a conference in the next few months where yet another award of international recognition will be bestowed upon Columbia Power.

In closing, Mr. Chair, I understand that this is the first time Columbia Power Corp. has been called in front of this committee. As a result, we may have gone into a bit more detail in the presentation than you may have preferred, but as the new kid on the block, I want this committee to know I consider the Columbia Power story to be a good one.

The province, I think, did an outstanding and visionary job in creating the CPC-CBT structure. I think it delivers the right mix of value to the shareholder, value to the community and an opportunity to advance the objectives of the province. It is my intention to attempt to move Columbia Power forward and beyond, because I believe we have created value in excess of the sum of the parts.

My colleagues and I would be pleased to respond to any questions that you, Mr. Chair, or any member of your committee may have. That concludes our formal presentation.

J. Rustad (Chair): Thank you very much, Barry. It was a very thorough presentation that we very much enjoyed.

J. Horgan: Thank you very much, Barry, Bruce, Randy, Lee and Neil as well — and the other person over there — for coming.

It was a very thorough presentation. We don't get that level of detail often from the larger Crowns, so it speaks to the good work of the staff to put this together.

You spoke of two legal issues. I'm assuming from the conclusion that the first issue was the channel cement work failure. The second issue was the delays at Brilliant. You spoke about risk transfer. I'm wondering if you could explain to me how, in the model, risk was transferred in those two instances. And what certainty do you have — certainly in the case of the Keenleyside failure — that the company will remain whole through whatever legal proceedings flow from that?

B. Chuddy: With respect to risk transfer, again, I joined Columbia Power in June of this year, but the risk transfer that I'm talking about is determining which of those elements the contractor should take the risk on and which elements Columbia Power should take the risk on.

In the case of the Arrow Lakes channel claim, that claim actually occurred after the plant went commercial, so the things that happened there were related to the original design of the plant, and we are in a detailed — if I can use that term — proceeding with subrogation counsel related to the claim. So the item that happened related more to the fundamental design characteristics of the plant and the contractor's interpretation on that. We have many lawyers engaged in that to sort out what those liabilities are and how they shake out, and we have received claims from our insurer, FM, that have compensated us for that.

In the case of the Brilliant expansion, the claims related to issues concerning geotechnical work and issues that existed to the time of the construction of the original Brilliant dam. Those risks were allocated to the contractor, and based on the legal opinions that we have solicited at the request of our board, we feel we have a very solid case in that regard.

With respect to Waneta, we're going through a fairly detailed process to ensure that we properly map out the risks of the project and to ensure that the sharing of those risks is properly allocated as between us and the contractor. Part of the reason for the delay is that I wanted to be sure that we've learned from the things that have happened in the past and are properly evaluating that — not only with our own owners consultant but with the contractor to be sure that the document, when it comes out for pricing by the contractors, recognizes that we need a reasonably good price but that we also want to limit the risks to which Columbia Power is subjected.

I hope I've answered your question as best I can. Well, I've answered as best I can; I hope it answers it the way you want. But if there's any follow-up….

J. Horgan: No, it was on: what, if any, acquisition plan do you have…? The initial vision for Columbia Power was the three projects: Keenleyside, Brilliant and Waneta. Do you have an acquisition plan, following the completion of Waneta, to continue growth for the company? Or is the board…? Maybe that's a better question for Lee. There are small projects in the Kootenays that are, I would argue, probably ripe for acquisition. Do you have a plan that you could make public?

L. Doney: The short answer, John, is that we don't have a plan at this stage. We're pretty well up to our elbows in issues right now from getting ready for Waneta. The board has discussed the opportunity for the future with the minister, and we've been given a green light to sit down and do some basic strategic planning. Those kinds of issues are exactly in our thought process, but we have not put together what you would call a strategic plan for after Waneta. It is certainly in the board's mind that they're going to do that. Until we had a CEO on line…. And obviously — Mr. Chuddy is here — we do. We just haven't put our mind to that.

But we have been having to go out and recruit people, so we need to talk about: "What about beyond Waneta?" I'll turn it over to Barry, because we have sort of endorsed the CEO vision, which we have yet to take much further to the shareholder, but it does give you a sense that those are exactly the kinds of things we're looking at as a potential for the future. Of course, we have a partner in Columbia Basin Trust, which obviously has a keen interest in this as well. But no, we do not officially have a plan until after Waneta, for example.

B. Chuddy: The only thing I would add to that is that we have, I guess as a part of our recruitment process, been given the endorsement to talk about a CEO's vision. That vision basically says that I believe there should be life after Waneta.

As I'd mentioned earlier, I think the value that's been created within Columbia Power goes beyond the sum of the individuals there. We've got a good-news story, and we don't want to be stopping at Waneta. Certainly, the interest of…. The people that are with the company and who want to continue on with the growth in the company believe we should be doing more.

At this point in time we don't have specific projects in mind, but I do believe that an entity with significantly more in assets and dollar value under control is quite doable.

C. Puchmayr: Just getting back, again, to the claims that are being made with regards to the two projects or the litigious nature of it.

What is budgeted on these projects for legals? Are you running into a situation where you may be going over budget for legal representation, or is that an unlimited budget?

B. Chuddy: We haven't budgeted what you might call a resolution of the claim. We have, I guess, done some work in terms of some legal costs that we're spending on a regular basis, but this is one of those things that takes the path it needs to take. We need to be there to defend our rights as a company.

Consequently, I'm not aware of any limitations in a budget per se, but we're cognizant of our legal costs. We're very specific about how we manage legal costs, only because we want to be sure that the result is that we're successful in resolving these to the benefit of Columbia Power.

C. Puchmayr: Absolutely. Do you know, offhand, what you normally budget annually for legal costs?

B. Chuddy: We’ve budgeted $3 million for legal costs for this fiscal year.

C. Puchmayr: You talk about some interpretation issues with respect to the contract that may result in some of the legal arguments or the legal challenge. Are those contracts available to the public? Are they on line somewhere where the public can look at what may be contentious here in this dispute?

B. Chuddy: I believe the majority of the contracts are commercially confidential, as would be the case with most independent power producers. They're not typically made public. I'm not aware of the public nature of those projects.

The one thing I should say as a follow-up to your earlier question regarding legal costs is that we did have a positive variance in our budget as it relates to FM, our insurer, paying some of the moneys for the legal claim. The issue we're involved in now is trying to get to resolution of those things. We're working very closely with FM and subrogation counsel. Again, there are a number of lawyers involved in that.

C. Puchmayr: I have one more question, and then I'll pass it on and maybe touch on a couple of issues after. You talk about first nations on slide 12. You make reference that you may have some first nations working on those projects.

Do you have an idea of how many first nations tradespeople are on, or are being trained for, those very projects?

B. Chuddy: I don't know the exact number. We can get back to the committee with that. I can speak to the fact that during my early tenure with Columbia Power, I had the pleasure of meeting a number of the first nations people that were involved in the Brilliant expansion project.

It would seem to me that it's a big number, but we can get back to the committee with whatever breakdown….

C. Puchmayr: If you're going to do that, could you also maybe submit the number of apprentices that are working on those projects as well?

R. Cantelon: A question on the Waneta expansion project. I see the flows are very early in the year. Is this basically to capture over-the-dam outflows in the spring?

B. Chuddy: Basically, the Teck Cominco dam spills at a number of times of the year. That plant was not built to capture all of the energy that can be produced. Based on the engineering analysis that we did, by building a dam of up to 435 megawatts, we can build a lot of capacity in that would otherwise be wasted over the dam.

As is the case with any power project, you tend to optimize based on the amount of flow you get at the majority of the times here. You don't ever get all of it. As power prices change, it becomes more economic to put more capacity in.

The other impact that has a significant bearing on the amount of power that the plant produces is the

R. Cantelon: Just a question, then. What's the current going rate of selling that power?

B. Chuddy: I don't know. I think the numbers are published in the 2006 call issued by B.C. Hydro, but we can get back to the committee with those numbers.

R. Cantelon: Just a general question finally, and that is: what would be the percentage of your total generating capacity as compared to the total hydro capacity of B.C. Hydro?

B. Chuddy: It's a very small number. I think 10 percent at the most — very small.

D. MacKay: You may have to forgive me for asking a stupid question, but what is FortisBC? I'm sorry. I'm not familiar with that term.

B. Chuddy: Fortis is a company headquartered in Newfoundland. They're publicly traded. In British Columbia they have had FortisBC — I believe it's an affiliate company — purchase the assets of UtiliCorp and West Kootenay Power. They are basically operating FortisBC as an affiliate of the larger Fortis company headquartered in Newfoundland.

B. Duncan: Excuse me. It's a utility that serves about 10 percent of the population of the province, some in the Okanagan, Kelowna and also in the Kootenays. It's nested within…. Then B.C. Hydro services around 90 percent. There are other small, municipal utilities. As one of the MLAs said, New Westminster is a utility that B.C. Hydro has. It's the other smaller regulated utility in the province.

D. MacKay: I'd just like to go back to slide 16, where it talks about — and I think Chuck Puchmayr touched on this — the number of first nations tradespeople. The way I read that, it sounds like you only employ native people with a trade. Is that correct? Or people who were going through a program?

B. Duncan: In our procurement proposals there are various aspects where money is spent with first nations. Some of the studies of the ethnology of the region will mean we are putting in plantings. There are some nurseries that the first nations run. Various work is done as some of the subcontracting. And then the actual construction of our facilities — there are programs that have first nations involvement in those.

We can get back with more specific information on those various programs, if you'd like.

My final question. It also indicates here that you fund an ongoing aboriginal community benefit and sponsorship program. How many native people that live in the area are affected by the funding program that CPC provides them? How many bands are there? Do you know?

B. Chuddy: There are two that have come up that I'm aware of. I don't know how many specific people are involved. We can get back to the committee with….

L. Doney: The two largest ones that directly affect CPC are the Ktunaxa, resident of the Kootenays, fairly large — I can't give you the exact number — and the Okanagan bands, who claim some of the area over there. We have community development partnerships with them. It's not a large amount of money, but it's some money for funding.

L. Doney: They claimed the use of the area, but they don't…. Other first nations across the border have also had the use of the area, before there was a border, so there are a significant amount of overlapping claims here.

D. MacKay: The final question is: how much do you provide to the native bands? It suggests there that you fund an ongoing community benefit and sponsorship program. What is the total cost of that?

B. Chuddy: The program is specific to the project. There is about half a million dollars in the case of the Waneta project. We tend to look at the expenditures for these programs based on the project's specific initiatives and line them up with the projects.

C. Evans: I want to direct my first comment to the Chair, and then I have some questions.

I wanted to start by objecting to the fact that this meeting is held in Vancouver. I think that of the people I see in the room, there are probably only two or three that live here. I'm guessing we spent 10,000 bucks to come to a town where these guys own no property and none of us live, and those people all brought….

I would just argue that in the future…. We all work in Victoria. We've got Fridays off. We could meet there for nothing, or we could go to Castlegar, where the projects are and where we'd actually be looking at the landscape we're talking about. I just want to put on the record that being here strikes me as inappropriate, given the wonderful opportunity we have to talk about a very specific organization that works on a very specific landscape.

Secondly, I wanted to be nice to the Chair and say thank you for inviting these people. I think this is a wonderful opportunity for us to learn about a Crown that is very poorly understood and sort of brand-new, so you did a good thing — half a good thing, anyway.

C. Evans: I think that some MLAs probably find it unfathomable that you're producing 10 percent of the power of B.C. Hydro and not flooding any land. Could you just say in layman's terms how it comes to pass that you can produce power without creating a new dam?

B. Chuddy: Very simply, what we do is look at those dams that are spilling water, and instead of that water spilling over the dam, we put it through turbines and make electric power of it.

B. Duncan: If I might, there is water that's being spilled at these facilities. Also, they're on international rivers, some of which have benefited from the Columbia River Treaty and the re-regulation from the storage facilities from the Columbia River Treaty. Under the treaty, the benefits of that re-regulation, in terms of power generation in British Columbia, accrue to the province. Teck Cominco or Fortis couldn't get the value of that upstream re-regulation, so we're able to optimize the facilities, both to minimize spill, in an economic way, and to crystallize value from the re-regulation benefits under the Columbia River Treaty.

For example, at our Brilliant expansion facility about half of the flows are Columbia River Treaty–impacted flows from Libby upstream. Our Waneta expansion benefits from Boundary dam, which is owned by Seattle City Light, and they regulate the flow. We're able to capture benefits that Fortis or Teck Cominco, when they owned the Brilliant dam, couldn't.

For the benefit of members, the person who just answered that question is one of the only seven people in British Columbia who actually could have.

I want to belabour the point just a second. The Keenleyside dam produced zero power. Could you explain to members why there's a dam in British Columbia that had no power-producing capacity?

B. Duncan: It is one of the three storage dams — the Hugh Keenleyside dam — that flooded the Arrow Lakes and connected the two Arrow Lakes into a large reservoir. There's something like 15 million acre-feet of storage in the Columbia River Treaty. Some of it's at Mica dam, some of it's at Arrow, and some of it's at Duncan. Duncan and Keenleyside are both storage dams. B.C. Hydro was pursuing the two-rivers policy and didn't have a need for it. They pursued development at Mica and at Revelstoke, which are around 2,000 megawatts apiece.

We put in a channel, took water above the storage dam, then put it through a powerhouse and then let it out below the dam, minimizing spill and generating power with the use of that upstream storage.

C. Evans: When that plan was first discussed, B.C. Hydro put the cost at $600 million. How much did it cost you to build the power plant at Keenleyside?

B. Duncan: Well, as part of what we have to do…. We don't have a provincial debt guarantee, and we're not a regulated utility, and we have to develop projects as an IPP would. When B.C. Hydro had the original concepts for Keenleyside — putting in a powerhouse — it was a 240-megawatt plant, and they had a different configuration for it.

We had to kind of re-engineer it to determine what the cost-effective scaling was. There's a tendency to build them as large as you can, as opposed to sizing them economically efficiently. We found that the economically efficient sweet spot wasn't 240 megawatts. It was 175, and then it could be configured up to 185.

We put out an owner's concept and then put it out to a design-build competition from Peter Kiewit and Harza and others. They came forward with a proposal around our concept. We had fixed-price bids. So we had a different concept scale design, and we had different bidding. B.C. Hydro's can tend to be a cost-plus approach, in a sense — how they do their bidding — although that's changed.

Ours are fixed-price contracts with certain specifications for how they have to build the plant, what power outage it has to have, the various performance…. Then we have to be duly diligent in ensuring that it's built to specifications and that we recover if it's not.

C. Evans: Okay. So you brought up the fact that most of these dams are affected by the storage capacity of the treaty. The treaty will be renegotiated in what year?

B. Duncan: Certain aspects of the treaty, certain clauses or articles of it, can be subject to renegotiation on ten years' notice, not to be given before September 2014. Certain clauses in the downstream benefit entitlement energy part of it, and how that's calculated and how it's shared between B.C. and the United States, can come up for renegotiation as early as 2024.

The treaty stays in place as long as the facilities stay in place. The amount of storage and the regulation of the rivers…. You'll still need a treaty under the transboundary act and the IJC. The treaty doesn't come to an end. Certain clauses can be subject to renegotiation.

C. Evans: Is it your expectation that Columbia Power would be part of any discussions about whether or not the treaty would be renegotiated with the province?

B. Duncan: B.C. Hydro is designated as the Canadian entity under the Columbia River Treaty, and it's been assigned the province's rights and obligations as part of that — at least, as the Canadian entity. Bonneville Power Administration and others are on the U.S.

L. Doney: Maybe I can add to that. The province has just set up a steering committee, and the Ministry of Economic Development has just invited Columbia Basin Trust to participate, and we expect to be invited to participate.

L. Doney: Well, my sense of the steering committee's job is to ensure that there is coordination for the negotiations.

J. Rustad (Chair): Everyone else had two. I'll allow you two. How many parts to the second question?

In the beginning, Barry, you explained that these projects operate under a 50-50 relationship with the trust. It is, I think, the belief of most of us that no business can run properly with 50-50 because there is no majority shareholder and a partnership breaks down and doesn't work. Can you tell us…?

C. Evans: Okay. It was, previous to your existence, my assumption — not anybody else's — that 50-50 with the region might not work. Can you explain how come it works and whether it might work for other resource opportunities elsewhere?

B. Chuddy: To answer your questions, "Does it work? Is it working?" I think it's working quite well. I think it's working in large measure because of Neil and myself and the people in the two companies.

Columbia Power is the operator and the manager of these projects. Neil and CBT tend to take on a role more as a financial partner, whereas we're more of an operational partner. To be frank, the relationship is going well to date. I think it can work well as long as it's clear what the accountabilities and responsibilities are.

I think we've done that very well with Columbia Basin Trust, so the short answer is yes. I think it can work well as long as there's clarity on who does what.

My first question. I appreciate the opportunity to learn more about Columbia Power as well. Actually, I'm very impressed that when you do the quick math in terms of the output and when the Waneta expansion gets on board, it looks like you'll have the capacity to power almost 300,000 homes, which is a significant amount.

I was wondering. I'm a big supporter of the province's goal for electricity self-sufficiency. You remarked earlier that this is one way in which we can help meet that. I know we have to import almost 13 percent or so of electricity.

Do you know what percentage, once you're at your 300,000, approximately? Could you maybe answer that? You may not have that at the top of your head.

B. Chuddy: I don't know, off the top, the percentage that the province of B.C. imports on a regular basis through Powerex and B.C. Hydro. It is clear that as we develop and commit projects like Waneta, we're helping that equation.

B. Duncan: If you look at our energy portfolio with Waneta expansion at 435, I think you get something in the order of 3,000 gwh — or gigawatt hours, as it's called.

I've heard it said by the IPPBC that there's around 6,000 gwh that on average over the last five to ten years has been imported. So you could look at it as probably half the quantity, although it doesn't necessarily all occur at the same time.

B. Duncan: And there's storage and other pricing things that impact where they are on the cycle for water and storage.

J. McIntyre: That's an impressive story. We may want to consider saying that, because it is an impressive statistic.

My other question, then, relates to some of the risks. Bear with me. If I've interpreted this correctly, one of the major risks you're now dealing with as you go forward — I guess related to Waneta as well — is this power purchase agreement with B.C. Hydro.

B. Chuddy: I'm cautiously optimistic. I believe the project represents good value for the province. We certainly would encourage our friends at B.C. Hydro to move quickly to allow us to build Waneta once we have a power commitment and a commitment of the capital cost.

I tend to worry, so the short answer is that that's something I give a lot of thought to. I want to be sure that we meet the requirements of our board and our shareholder and have clarity on who's buying the

power, what they're paying and what the capital cost of the project is. Until you get to the end in the power business, none of the pieces mean much. You have to get them all there at the same time.

B. Chuddy: All I can tell you is that, to date, we've been working quite cooperatively with B.C. Hydro to achieve those objectives.

B. Duncan: I could add one other comment. You produce energy with a 435 megawatt — Waneta — of around 3,000 gigawatt hours, as we've said. Also, there's capacity. The plants produce almost 900 megawatts of capacity at a 435, which is the same capacity as Site C, although we don't have the water all the time. On average, B.C. Hydro has around 65-percent capacity utilization — that's what it's called — with the amount of water that they have and for the size of the facility. Ours are significantly lower.

For Waneta expansion, it would be down in the order of 25 percent or so. But we have two products, really. We have energy, but we also have capacity. Because of the upstream storage and regulation at Boundary and at Kootenay Lake — we own half the storage on Kootenay Lake; we have water rights to it — and being able to benefit from Columbia River Treaty storage, we have non-trivial, dependable capacity. It's not 100 percent of the installed capacity, but it is very substantial.

At a 435-megawatt plant we would have 375 megawatts of capacity, depending on how many hours B.C. Hydro rates it. We bring substantial capacity. The question is: in the calls that B.C. Hydro does….? They typically do calls for energy. Then capacity sort of comes along with it.

Because our facilities have this upstream storage and we're adding to the amount of capacity that can be generated from the dispatch on the Pend-d'Oreille, the Kootenay or the Columbia, that dependable capacity is a very real and valuable product. B.C. Hydro hasn't always been able to fashion its calls to specifically get at this capacity issue as well as the energy.

We also provide system benefits, because we're effectively taking away constraints. Before we built the Brilliant expansion, there was a lot of spill going on, on the Kootenay River. It actually became a choke point. Because of federal fisheries and other concerns about fish, they would have to minimize spill and they would have to operate the whole system differently. We are able to generate substantial benefits because we're getting rid of a constraint, which allows us to process more water.

B.C. Hydro's Canal plant, which is upstream, can operate more efficiently. Similarly, when you do a Waneta expansion, that's the other choke point on the Pend-d'Oreille. I think Boundary is something like 700 megawatts, and Seven Mile…. They're in that order. Teck Cominco's facility is only in the 400-megwatt range. It is undersized by over 300 megawatts right now in terms of its constraints. They run it differently. They want to minimize spill during the day, so they have to run it down at night so that they have more capability in the headpond to absorb water during the day and they process less water in the valuable periods.

We're able to generate more energy from avoiding spill. We're able to create value by getting rid of constraints upriver in B.C. Hydro's system, and we're able to move energy — water — through turbines from low-value periods into higher-value periods. There are a number of aspects — the system benefits, the time-of-use benefits and the amount of increased water you can process through turbines. Those things are very complicated and aren't well suited to a heads-of agreement that Hydro would put out in an open call.

With our Brilliant expansion, we had parallel discussions with B.C. Hydro. It had its RFP, and some of the terms and conditions of its call affected the terms and conditions that we had under our RFP. We're having discussions again with B.C. Hydro.

It's such a large facility at 435 megawatts. It's the same as a Revelstoke unit 5 or unit 6, which is 450 megawatts. It is very large in terms of a machine, and it has to be used in the Columbia-Kootenay system in the right way. Those things are subject to detailed negotiations.

It is also on an international river. It affects flows at the border with the Americans and assured annual operating plans, etc., for B.C. Hydro.

J. Rustad (Chair): I'm putting myself in next. I wanted to ask you a question with regards to the Canadian dollar and the fluctuations in the Canadian dollar. I know that has a potentially significant impact for your operations in terms of your budgeting, so I'm wondering how the rise in the dollar has perhaps affected your budgetary situation.

What steps do you plan to take place in future, assuming that we have a stability somewhere up in this level of the dollar?

B. Chuddy: Typically, the exchange rate between the Canadian and the U.S. dollar has an impact on power markets generally between Canada and the U.S. It's more impactive in terms of the price that B.C. Hydro might attract in that it sells power at some times and it buys power.

To the extent that we denominate our power in Canadian dollars and have a long-term power contract with B.C. Hydro, it doesn't have an impact on our project per se. But it may have an impact on the value that B.C. Hydro may see for power going forward, given that there's less incremental value that you might get out of power projects south of the border.

To be clear, our intention is to sell as much of the power in B.C. as we can. To the extent that we finalize a long-term power purchase contract with B.C. Hydro

or another B.C.-based company, then we have very little exposure to the Canadian-U.S. dollar.

I want to touch, for Joan's benefit, on the self-sufficiency issue. Barry, you touched upon it for a moment.

As I understand it, the self-sufficiency argument or directive is about annual energy capability rather than meeting peak demand capacity. So the notion that the lights are going to go out for fear of not having our electrons generated in British Columbia is really a fallacy. The argument the ministry has put forward is that over the course of 365 days you must purchase this much power within your borders, but it doesn't do anything about addressing the challenge of peak demand, which Waneta will by virtue of its storage capacity.

Could you comment, perhaps, on how self-sufficiency really has any impact at all on Columbia Power, beyond you being a Canadian producer?

B. Chuddy: It doesn't have a direct impact on us. I think it's just good business to ensure that you're underpinning your requirements with largely domestic needs. This is something that isn't uncommon in Canada. I know that certainly in Ontario and in B.C. it's just good business not to put the ratepayers at risk for the sake of costly imports from other jurisdictions.

How do we help that? We help that by producing energy that is available within the province on, as that portfolio slide shows, a pretty regular and definable basis. The self-sufficiency initiative doesn't have a direct impact on us in the context of prices we might attract, etc., but clearly, the projects we are developing and bringing forward are adding to the objective of attaining self-sufficiency by producing more energy within the province of B.C.

J. Horgan: You made a comment, Barry, about high-priced imports when, in fact, we buy low and sell high. So the notion that we're at risk because we're buying at four in the morning and selling at six at night…. I don't know if that's good business. I always thought good business was buying low and selling high, which is what PowerEx and B.C. Hydro have been doing for 20 years to the benefit of all ratepayers and to the treasury.

The notion of paying too much for long-term, fixed-price contracts so that we can say the electrons were generated in British Columbia is actually doing a disservice to ratepayers, in my mind. But I'll move on, because I know Joan won't want to belabour that economic argument too much.

B. Duncan: I would just say that we're not here to speak to the energy plan. We think we're an important part both of creating more energy and of providing capacity, which is the ability to deliver energy into the valuable periods of heavy-load hours.

It's true that you'd like to be able to buy when the price is low and to sell when it's high, but we're building facilities that are going to be there for 70 years, and the price patterns that we've seen have been relatively recent. The test will be the relative values over the life of the project. It's important to have the ability to meet your needs in heavy-load hours. There are transmission constraints in these other markets, so I think you have to have a degree of self-reliance.

J. Horgan: My next question would be…. With respect to the Columbia Basin Trust–Columbia Power model, there's talk about looking at Site C as an option on the Peace. I'm wondering — maybe this would be better to the chair — if on the board or in your discussions with the shareholder there's been any discussion about a Columbia Basin model in the Peace if we were to proceed with Site C, so that, as we did in the Kootenays, sharing the benefits of electricity production with the communities would be an option that you would recommend to government.

L. Doney: We have not had any discussion, nor have we been approached. Depending on what the model looks like and who's involved…. All these things are about who you've got involved.

To go back to the question that Mr. Evans asked: why does it work? Recently our board was changed, and we have two direct representatives from the Columbia Basin Trust sitting on the CPC board. The two individuals that were picked and nominated work very well with Columbia Power because of the way the chemistry works.

In my experiences, joint ventures either work like crazy, or they fall apart. It's usually all about relationships. So far we've got a really good relationship with our partners.

It could work — absolutely. But it depends on who the partners are going to be and what the relationships are like.

J. Rustad (Chair): Thank you. I'll just remind all members that the goal here is to review the annual reports and service plan of the Columbia Power Corp. That last question kind of strayed a little bit away from that.

D. MacKay: I'm going to go back to the $500,000 that appears to flow to the two native bands affected. I wonder if you might get for me — you probably don't have it today — the names of the two bands that are receiving the $500,000. I'm assuming that's split between them. Could you get me the number of people within the bands that are in receipt of that money? Can you also tell me when the money started flowing to the native bands? Is there an end date to it, and is this a fixed price and for how long?

B. Chuddy: I can't answer those questions today, but we will get back to you.

C. Evans: I wanted to ask…. In your opening slides, Barry, you talked about the necessity for the reporting relationship between Columbia Power and the government to be different than IPPs. I guess I've come to the conclusion that the reporting relationship required of a Crown is somewhat onerous and expensive, and I've also come to the conclusion that that's a good thing. I wonder if you can explain to us what your reporting relationship to the Crown is. What do you have to go through in terms of justifying expenditure and budgets as compared to an independent IPP?

B. Chuddy: I can't speak to all of the details of what we go through because I'm relatively new. But I am aware of our obligation to produce a service plan and a budget, and it's quite reasonable. It's onerous, but it's reasonable.

I guess my experience with IPPs relates to publicly traded companies where the shareholders regularly put you on the carpet to determine if you're meeting your return expectations and if you're spending money prudently. But with respect to the process that we go through, it is a bit onerous and does require us to go through a number of steps. Specifically, what those steps are….

R. Smith: It starts out with the BTA Act and involves service planning, providing annual budgets and then reporting on that through the annual report process.

B. Duncan: The Budget Transparency and Accountability Act. There's the Financial Information Act. A lot of it now, with the administration, is streamlined into the annual budget process. There's the service planning and the annual reporting.

In addition, under the agency agreement that we have with the province, all material decisions require Treasury Board approval. There is currently quite a low threshold for that. It was developed in 1995, when it was a startup company and there was an assistant deputy minister and a director from government who were a paper company doing it. I think it was $250,000 for a power project and $100,000 for a non–power project that was the tripwire for seeking Treasury Board approval if it was done outside of an annual budget process.

Clearly, we try to do as much under the annual budget process as possible. Outside of that, it then became crystallized around decisions to build projects — a major decision to build a project but also marketing decisions and others, sometimes insurance or contracts to sell.

Treasury Board can have a fairly long time lag, particularly in budget cycles, to get submissions through. As things get more complex on this, to get a Treasury Board analyst or an analyst in the Ministry of Energy to get their minds wrapped around some of these issues — Columbia River Treaty flows, etc. — can take a lot of time. That's a relatively onerous process as well.

C. Evans: You have good bond ratings, and you don't have government guarantees, so it is my impression — and I would like you to tell me if I'm right or wrong or if I made this up — that the reporting relationship with the Crown is paid back when you go to raise funds on the market. The market perceives that you are solvent and legit because Treasury Board has already agreed that your facts and figures are what you say they are.

B. Chuddy: The amount of rigour that one goes through when they do a bond issue, or any kind of project financing, is intense. The lenders put us through a significant amount of scrutiny in any of those bond issues. I think the fact that we're real, if I can use your term, doesn't hurt that argument, but the lenders satisfy their requirements regardless of whatever other processes we go through.

As much as the process we go through is rigorous and creates a lot of work for us, we go through it, and we do it as well as we can. But that doesn't in any way get us a reduced requirement when it goes through the process that the lenders put us through.

L. Doney: If I can just comment on that. With the establishment of, if you like, a set of independent directors on the board, with a separate finance committee and with the Auditor General being our auditor…. The chair of our finance committee is a former CFO at Canfor. His comments to me were: "You know, Sarbanes-Oxley and the public trading commitments that you now have to make as a public board are very, very taxing." Basically, the public commitments you make through a Crown corporation are…. But they're actually, in some ways, easier. With a Crown corporation, then, you're not then having the publicly traded corporation and what's going on….

I don't think it helps us on the financing side because we go through such rigour anyhow, but we've been able to lower some of these trip points now with Treasury Board because we've got our own systems in place. That's made us, I think, a more efficient company.

C. Evans: My next question is: now that you're 12 years old, are there other entities anywhere in North America like Columbia Power — in other words, a regionally based resource company that shares revenue with the people of the region? Secondly, have any other regions of British Columbia or Canada or the United States attempted to come to you and say: "How did you do it, and how does it work?"

B. Chuddy: I guess my experience in Canada and doing power projects in different jurisdictions around the world…. Most responsible developers always do invest an increment back into the community in some way, shape or form. Be it through prescribed funding

mechanisms, developments or community involvement, that's what responsible developers do.

I'm not aware of a structure exactly like the CPC-CBT structure, which is very prescriptive in terms of the amount of the dividends that make their way back into the community. I can tell you with certainty that it's quite a pleasure to be working with a company where the local community asks you when you're going to bring the next project on line. I have never, in my experience, had that happen to me before. I think it's a good-news story.

The fact that it's prescriptive and done in a certain way…. I'm not aware of any other jurisdiction where it's been replicated exactly like the CPC-CBT structure. We invest an awful lot of money back into the community. Most other developers probably wouldn't invest that much.

I'm not aware of the exact structure being replicated anywhere else. It's working well for us for the reasons mentioned.

B. Duncan: There was a World Commission on Dams and a report that was done in 2000. We made some presentations to it. I think the CBT did as well.

I think we're relatively unique, but the commission's report recommended that people affected by facilities have a vested interest in the benefits that flow from them. It was the right model for approaching these issues on major water projects and others.

When we go to the Canadian Hydropower Association or other international hydro power associations, people are interested in the model that we have because I think it's relatively unique.

C. Puchmayr: Two questions. You spoke a while ago about the ten-year notification that can be given — I think in 2014 — that there's an intention to renegotiate some of the treaty. So that would be 2024.

On that, are there some projections, or are you seeing some contentious issues now that may be on the table? You talked about a steering committee or some committee and that you will be having those discussions already, even though it's far down the road.

Are you anticipating some major changes, or are you hearing some overtures from our friends south of the border?

B. Duncan: To be clear, B.C. Hydro is the Canadian entity under the treaty. The clauses that can be renegotiated deal with the energy…. Downstream benefits is the term that's used. It's the increased generation in the United States from the regulation of the flows from the treaty facilities in the United States and in Canada.

Originally, there was a 50-50 sharing — that was the concept — and a U.S.-Canada engineering board that was done and reported to the International Joint Commission.

That clause can be…. What's the quantum of benefits, energy and capacity, and what's the relative sharing? Those are issues. Facilities in the United States are subject to review and relicensing. We've had to deal with something that's called VARQ, which really means "variable quantities."

Increasingly, in the United States, fisheries agencies are issuing different rules for releases from storage facilities. Effectively, storage facilities change the flow pattern over time, and they're trying to go back to the more natural flows when there wasn't the storage facility in the first instance.

The relative priorities between flood control, which is the primary one, and energy production, which is the secondary one under the treaty, versus other multiple uses — including fisheries usages, community water and other uses — are clearly changing over the last decades. We've seen that with these so-called VARQ flow regimes for Libby and Hungry Horse dams in the United States.

We deal with the corps of engineers and the bureau of reclamation in their environmental assessments that they have to do in the United States. I think those and the communities, in terms of how things are operated…. The Columbia Basin Trust has a water initiative that they're trying to have as a focal point for input regionally in the province.

I think that all those things — the changing relative priorities of use, population growth, climate change, all kinds of things — that might affect over the very long term are things that come into the mix.

C. Puchmayr: It's interesting when we hear that people are looking at studies south of the border on eliminating certain dams to allow for natural fish habitat again.

My second question is…. You talked about when you build a project and you sort of put a 70-year lifespan on it. I look at a bit of the research that I've done on the independent power producers, and I look at the fixed rates until the end of those contracts. The fixed rates mean that they have to supply it — well, not to our grid, because our grid's bilateral — to B.C. Hydro.

At the end of those contracts, they're able to sell anywhere. So when we're talking about building 70-year life-cycle projects, at the end of these IPP projects, those projects that we've built will have only 30 years of life left. What kind of modelling are you doing now in case there suddenly becomes, after the IPPs mature, a real crisis in not having any local power available to purchase at reasonable rates? We're sort of left trying to purchase power at market rates or at blackmail rates.

B. Duncan: Once again, with respect, I think we've moved into issues that are more B.C. Hydro issues, relative to how it structures its calls for energy.

J. Rustad (Chair): If I could interrupt for a second, I just want to remind all members that the intent of this is to review the annual report and the service plan of the Columbia Power Corp. I'm going to rule that particular question out of order because it is not related to the….

C. Puchmayr: I'd just like to challenge that, Mr. Chair. We talked earlier about how a private company has to meet return expectations of their shareholders. The people of British Columbia are actually the shareholders of this, so I'm asking the questions as they were put across to us. I'm asking: how does it meet the expectations of the shareholders, which are the people of British Columbia, for future power issues that may affect these projects that you govern or manage?

B. Chuddy: There's a trade-off in any and every power project that relates to the amount of capital you have to keep putting into it versus the value and the benefit that it brings forward. In all of our plans and pro formas and all of our projects, we assume a certain amount of capital.

There is no project — be it a hydro project, a fossil project or even a wind turbine — that runs forever without the addition of incremental capital. The longer you go out in a power project, the more capital you have to put into it. So there comes a point in time where you look at the value that you're going to get for the electricity versus the amount of money you have to put into it and the terminal value of the asset, and you make a determination. Does it make sense to keep going?

In a case where you don't have a 50-, 60- or 70-year power contract, often the planning horizon that you can use as an IPP or a Columbia Power is predicated on the term of the concession. Our shareholder and our board would be reluctant for Columbia Power to bring a significant amount of the value we have forward at the risk of what future markets might bring to us, because while one prediction is that power prices are going to be very high and you're going to make a lot of money if you sell the power out of this depreciated plant, the other side of it is that power prices might come down. If you've got to invest capital, that's an analysis you've got to weigh very carefully.

It's a difficult question to answer because what you do at the end of the life of the project is a function of many variables. What is the price of power at the time? What is the appetite of the shareholder and the board to take on the risk that you don't have a long-term contract? What is the amount of sustaining capital? What is the amount of energy? What is the amount of available water?

It's difficult to answer your question, to say that at year 70 this project is going to be worth a lot of money. If there's a lot of water, if you don't have to put a lot of money into it and if power prices are good, you might be right. But if you have to put a lot of money into it to rebuild the dam, if you have to rebuild the turbines, if power prices come down or if there isn't very much water, all of those things will drive the value the other way.

C. Puchmayr: That's a fair answer, and that's why I wanted to know if there was any modelling done with the IPPs that have a 40-year guarantee of a very high rate of return. At the end of those 40 years, they no longer have to sell to our system. They can sell to the international grid. That's the only reason I was asking. Do you foresee some modelling to do "what if this happens?" Is that part of your governance, to model that?

B. Chuddy: Absolutely. In fact, in every single project we have, there is typically a terminal value, which is the value of the asset at the time. There is also the reclamation value. Because the amount of money that you would identify for those items is in some cases 20 or 30 years out, often you'll look at the terminal value versus the reclamation value as being about equal.

As you get closer to that period of time, you make a determination. Every IPP that I'm aware of has, in their pro formas for each project, both a terminal value and a reclamation value to take the project apart.

B. Duncan: I'll try to be brief. Our facilities are being built on international rivers with very heavy water flows.

Our Arrow Lakes Generating Station is a seven-storey-high concrete structure abutted against, through a channel, a B.C. Hydro storage dam on one of the largest rivers in the world, the Columbia. So the specifications…. I've heard it said that we were building pyramids, in effect, with the amount of concrete and steel that goes into these structures on these international rivers. We use a 70-year life for depreciation, but those facilities are going to be there for a very long time.

What happens is that we have sustaining capital. On the machinery and equipment in the turbine runners and things like that, the very big pieces, we use around a 35-year life, and then we have sustaining capital, as Barry said, every five or ten years.

The IPPs that B.C. Hydro is potentially purchasing from aren't necessarily…. We're almost unique. They're not on international rivers. They're small run-of-the-river IPPs. Some of them have penstocks that are relatively small coming down — they may be five, ten, 20 or 30 megawatts, not 400 megawatts. Gas plants and thermal plants are largely a concrete pad close to a gas line, and they have around a 35-year life. Then the machine becomes aged and needs to be replaced.

Our facilities are quite different in that regard. B.C. Hydro has a supply-demand balance that goes before the Utilities Commission every few years. It'll be updating its long-term acquisition plan against the supply-demand balance. The supply-demand balance takes into account load growth — demand growth — and also the resources it has to meet that demand — including purchases from IPPs, which since the late '80s have grown in terms of the volume. It knows the contract length.

Now, some of those facilities may not have any life after 20 or 30 years. It may be that that's their useful life, and there's nothing left to contract from. That won't be the case for us, and it's arguably a reason why we're a public asset on an international river system. These will be very long-lived facilities.

We purchased the Brilliant dam. It was built in 1944 by Teck Cominco. We paid $130 million; we spent $100 million to extend its life. We increased the size of it from 120 megawatts to 145 megawatts. We also did a major life-sustaining program in terms of the seismic upgrading, the facing of the concrete and a bunch of other things.

So it's very different. We're not a regular IPP. We're not a thermal facility. We have a different profile, a different life, but B.C. Hydro does take these things into account and has to go before the regulator, the Utilities Commission, and justify what it's doing in its long-term plans, which are at least ten- or 20-year forward-looking plans.

I. Black: I wanted to bring us back a little closer to what we're here to chat about. Bruce, you just made a comment that's a very good segue into my line of questioning. It has to do with the reality that you are very much in an eco-based business. I mean, the flow of water kind of determines how you guys do.

You've seen power sales and net income experiencing a spike in '02-03, then in subsequent years being considerably lower and then the net income having steadily declined since '02-03. On top of that, I note that in '05-06 your sales increased from the previous year, although your net income dipped a wee bit. Against that kind of financial inconsistency — good, bad or indifferent but not predictable — you are a water-based business in an environment that is now discussing very openly the realities of global warming and climate change.

My question to you: what assumptions and/or what contingency plans do you have in place going forward, both for the viability of the infrastructure and investments that you've made around that infrastructure and for the financial viability of the organization?

B. Chuddy: Let me address that by putting some information on the table on what we do on all of our projects today. We've negotiated an entitlement agreement with B.C. Hydro that makes certain assumptions on how the water would be available and how it would be used. In that agreement is an effective transfer of risk from the entity that's controlling the water and how the water flows to them versus to us.

In other words, we get a profile of revenues, if you will, that's somewhat indifferent to the actual flow of water because of the arrangements that we have in place with the entity that's controlling the water. That's for good reason. That permits the entity, in this case B.C. Hydro, from controlling water in a way that's optimal for the system without hurting us financially. Inherent in that is the mitigation of some of the risks you might otherwise see in that regard.

Fifty years out, though, when the agreements expire, there may be a different scenario, but during the term of our contracts with the utility there is a reasonable sharing of risks done in that way.

I. Black: Within that context, as the next decade, let's say, of that 50 years plays itself out, we will become more knowledgable about the trends that we're seeing on the environmental side — about water availability and other elements of climate change.

The financial mitigation — I accept that at face value. However, on the environmental responsibility and environmental stewardship side, what types of actions can you take or should you take or will you take as that information becomes available to balance it off against and to kind of reconcile with the financial piece of it?

B. Chuddy: Columbia Power is a relatively small player, certainly in the North American market, so there isn't an awful lot we can do except continue to develop the projects that we think are environmentally responsible. It's difficult for us to take on a major initiative in North America, given the size of our company relative to others, so I don't know that there's much we can do.

B. Duncan: I have a couple of comments. First of all, you said "the volatility of our net income." You referenced, I think, 2001-2002 or something.

We brought Arrow Lakes Generating Station in a year early. As part of that, we were then able — because we had it under contract to B.C. Hydro from 2002 on and we brought it in early — to sell the power that we received early into the United States export market. It just so happened that we matched the market in California. So we did very well indeed.

We did a revenue-sharing split between ourselves and Peter Kiewit, the construction engineering company. But the volatility, the lumpiness, of the revenue stream there came from our windfall, if you will, of early power sales.

B. Duncan: Now, the Arrow Lakes Generating Station output is sold under fixed-price contract through 2015. That's very stable.

As Barry said, we have these entitlement agreements, and we have 50-year flow sets or 70-year flow sets with B.C. Hydro. We look at the year-over-year volatility of that.

For Brilliant plant, for example, we get around 90 percent. Our average is around 90 percent. It's called a firming factor. We get around 90 percent output. They get the full output of the plant, and they dispatch it within their system.

We have long-term certainty on the contract. We have a contract with Fortis for the output of the Brilliant plant that runs through to 2056. It's a 60-year contract under fixed but escalating prices. For the Brilliant expansion we have two contracts that are 20-year fixed-price escalating at half the rate of inflation. Those will all be stable. What you saw was the early completion.

The other issue on hydrology. We did get involved in B.C. Hydro water use planning. As I said earlier, the Americans are very interested in these issues and in the Columbia River Treaty and all that. So they are doing major planning in the United States.

We've got involved in some of the VARQ analysis, and we've also participated in B.C. Hydro's water use planning, which looks at some of these very long-term issues. We have engaged in that, but we are within the integrated system. B.C. Hydro is the system operator and really dispatches our plants within its own value equations and things. They look at these things on the broad, very long term.

D. MacKay: I just wanted to take you back to the Columbia Basin Trust Act, which I think was formed in 1995. From my reading of it here, it sounds like about 8 percent of the downstream sales are returned to the affected area, in the Columbia Valley.

On page 5 it talks about the fact that for 30 years the sales have already been finalized. It mentions here that in exchange, the province received $64 million plus one-half of the downstream benefits, which it sold to a consortium in the United States for a period of 30 years. So I just wondered: at the end of 30 years, is the 8 percent of the downstream benefits…? Will they cease then, or are they just ongoing?

B. Duncan: No. The $64 million was a payment made in 1964, and then there were other payments that were done in the selling of the downstream benefits. So when the treaty was originally entered into, there was the forward sale, for 30 years, of the power, because the downstream benefits that we get from our one-half share of the increased generation in the United States were sold to a bunch of mid-Columbian utilities in the United States.

That money was given to B.C. Hydro. They used it to build some of the storage facilities, and they depreciated over time. So if you look at B.C. Hydro's balance sheet, it'll have contributions, and it will have Columbia River Treaty, and that number is depreciating over time. I forget the specific annual depreciation amount, but it's running down over that 30-year period.

When that sale came up, then, in the mid-'90s, the government…. There was another 30-year tranche to go to 2024. There were negotiations. They entered into an MOU, and the Americans were going to buy it. Then they decided they didn't want to. They walked away from the MONA, as it was called at the time, so Powerex markets that power for the province.

The 8 percent that we're talking about was the share of that estimated subsequent 30-year sale of the province's half of the downstream benefits between 1994 and 2024. That 8 percent was deemed to be an appropriate share with the people of the region, which was used to form some of the equity investments into these projects.

It really was just a notional appropriate sharing of the revenues from that subsequent downstream benefits 30-year tranche from '94 to 2024 that the province put into the equity for these projects. Rather than a transfer of 8 percent of this number, they wanted to create an annuity by investing in power and generating revenue streams over the very long term that were stable.

D. MacKay: Okay, but I'm still confused. Does the 8 percent continue when the 30-year contract is up? Will 8 percent of the downstream benefits accrue to the people in the Kootenays?

B. Duncan: The government, rather than give them a stream over time, calculated the 8 percent and put it into equity investments, so we had $50 million a year for ten years that were appropriated between 1995 and 2005. Half of it was equity that went to CBT, and half of it was CPC's. The province did a 50-50 joint venture. We then invested in the power projects, and we then spin off net income that goes on for as long as the projects go on.

It turned this 8-percent lump sum, if you will…. Rather than do regional economic development projects, it turned it into these power assets that turned it into an annuity that will go on for a very long period of time. Then half the net income accrues to CBT, and half the net income accrues to us. We retain certain for sustaining capital and cash flow requirements, and then we pay dividends to the province and to CBT.

CBT uses their half of the net income stream to fund good works and other things in the region, but those things will be there now for a very long time.

J. Horgan: Just a point of information, following on Bruce's comment about the MONA, which the Americans walked away from in 1995. They said that it was too rich. It was a $250 million deal.

By walking away from that, the Americans quadrupled their costs, because shortly after the MONA was ripped up, electricity prices went through the roof. So the benefit to the province has been going up almost exponentially as power rates go up. It was the best broken deal we've ever had.

B. Duncan: They regret it. The other thing is that with things like global warming and water shortages, it means that the value of the energy is likely to go up. So to some extent, from a financial point of view, if you have less energy but it's more valuable, your net income may actually increase.

C. Evans: Dennis, the short answer to your question is no. The 8 percent will not carry on.

While I appreciate Iain's question about climate change in this respect…. With the exception, I think, of Pend d'Oreille and Waneta, the other projects Columbia Power runs are largely historically fed by snowfall, which is changing. Iain is correct. I think the Columbia Ice Fields have disappeared by something like 25 per-

cent in 20 years. That means that what is many, many years or maybe eons of snow is showing up as water, which is coming to these guys' dams and being turned into money. Within the 70-year lifetime of the project, that will cease because the ice fields are disappearing.

I don't think Columbia Power could be expected to predict that impact, but it is a wonderful thing that their contract with Hydro is adjustable according to volume, because that is exactly what will be affected — volume — as opposed to price.

What I wanted to ask is whether the board could think hard…. Earlier, Lee said that now that there's a CEO in place and the CEO gets to make a plan, it's time to turn people's minds to what happens after Waneta. I believe that in two respects it would be a good idea to diversify away from hydroelectric and perhaps towards thermal or wind.

The first respect is — it deals with Iain's question — that it would create a diversification away from hydroelectric, climate-driven, moisture-driven income. Secondly, in part, the trust hangs together and the support for Columbia Power is throughout the basin because it was assumed that there would be three projects. People then assume that there might be investment closer to where other people live, and all three projects that you have built or are building or will build are within 50 miles of each other.

So my question is: has the trust engaged any consultants' activity or internal activity to begin to assess non-hydroelectric opportunities for electrical power generation in other parts of the basin, after Waneta?

B. Chuddy: The short answer is no. We haven't started the strategic planning process yet. That's something that we hope to get to — in fact, I want to get to — because I do believe that there are opportunities.

To your point: diversity isn't a bad thing. To date, all of our projects have been hydroelectric, and that has done very well for us and continues to bode well for us. Will we look at other things? It depends on the outcome of the discussions with our board and with our shareholder as to their willingness to permit us to look at those things.

Are there opportunities? The short answer is yes. The question is: are they opportunities that the province of B.C. wants to move forward on? I can't answer that question. It's beyond my scope and my capabilities in terms of understanding.

The short answer to your question is: we will review that in some detail with our board and with our shareholder. I take your point. In fact, I think it's a valid point that diversity, particularly in light of some of the changes that may be coming forward in terms of global warming, isn't a bad thing in terms of long-term sustainability. So we're going to be evaluating that in some detail as part of the strategic planning exercise. We have not retained anybody to do that to date.

C. Evans: My last question goes back to Joan's question earlier about negotiations with B.C. Hydro. I think it would just make all the sense in the world if Columbia Power was able to sell your production to B.C Hydro to mix in with the other assets that they have around the province in order to mix your capacity with other resources.

I think it would be a terrible thing if Columbia Power had to sell your power to a third party or a direct buyer because of the seasonal nature of your production. So my question is: what is the date by which you have to sell Waneta to Hydro, after which you will seek another buyer?

B. Chuddy: The short answer is that before we can commit the project, I need to be able to convey with certainty to our board and to the shareholder who we're going to be selling the power to. So if you look at the sequence of events that we have in front of us, we intend to issue an RFP to contractors very early in the new year.

It's going to likely take them something in the order of six months to come up with the capital cost, so the contractors will only hold their prices firm for a period of time. From a practical perspective, I can't permit this thing to drag on too much longer. Otherwise, we're collectively going to be spending a lot of money on an RFP that arguably might have some limited amount of value if we can't commit to construction of the project within a reasonable period of time of getting the capital cost pinned down from the contractors.

What is that period of time? I think that by early next year I have to have some certainty as to who's buying the power and under what terms they're buying the power. Otherwise, I have a difficult time in pulling together the continuum of all the pieces that have to go together to commit the project to construction.

We would like to be in a position, with the support of our board and our shareholder, to make that call on the commitment of the project sometime in fiscal 2008-2009. So the short answer to your question is that I don't think I have more than several months to be able to confirm who's buying the power and at what price.

L. Doney: And let me just add that we share your view too. The first preference of a buyer would be B.C. Hydro.

C. Evans: If you have to have it sold or you hope to have it sold within a few months — say, three months — then, don't you have to be looking right now for somebody else?

B. Chuddy: We've had a number of people approach us that are interested in buying the power from Waneta. Our preference and the expressed preference of B.C. Hydro is that they would like to buy the power.

We want to get a little more certainty on that transaction before we tell everybody else that we're not going to sell to them.

C. Evans: Me too. It's just that you have an easier time selling me your car if you've got another buyer in your pocket, you know.

B. Chuddy: I take your point. We don't want to be chasing three rabbits and ending up with a mouthful of fur. Yes.

J. Rustad (Chair): On that note, I'd like to thank you today for coming before our Select Standing Committee on Crown Corporations. I think it was a very informative session, particularly being that this is the first time that you've been before the Crown Corporations Committee. I think you've done an excellent job in explaining the details of your annual report and your service plan. So thank you very much.

We've got a couple of other things on the agenda, so maybe we'll take just a minute or two. Then we need to briefly go in camera and then discuss our next meeting date.

J. Rustad (Chair): We'll call the committee back to order, and I'll be looking for a motion to go in camera.

Can you explain to me what the purpose is of going in camera? What is the test of going in camera and not going in camera?

J. Rustad (Chair): The purpose of going in camera in terms of some discussion on this is that this will ultimately lead to the final report, and it would be inappropriate for that information to be out in the public prior to the final report being released to the House.

J. Rustad (Chair): We've been in camera, discussing the presentation by the Columbia Power Corp. and its implications for our final report.

At this time we have one other item on the agenda, which is any additional business. I just wanted to make a suggestion that we're looking for an opportunity to bring forward a couple of other Crown corps before the end of this session. I was considering calling for one in December and one in January, but in the light of Corky's earlier comments, perhaps….

I was going to make a suggestion that we shoot for a date in January to review two additional Crown corps. What I just want to know is the availability of people in January. Would it be better for early January, mid-January or late January?

J. Rustad (Chair): Okay, so we'll look for a date sometime mid- to late January for the next meeting.

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	Witnesses:
	• Barry Chuddy, President and Chief Executive Officer
	• Lee Doney, Chair, Board of Directors
	• Randy Smith, Chief Financial Officer
	• Bruce Duncan, Vice-President, Strategic Planning and Regulatory Affairs

Committee Staff:	Jonathan Fershau (Committee Research Analyst)

REPORT OF PROCEEDINGS (Hansard)

SELECT STANDING COMMITTEE ON CROWN CORPORATIONS

REPORT OF PROCEEDINGS
(Hansard)

SELECT STANDING COMMITTEE ON
CROWN CORPORATIONS