LEGISLATIVE ASSEMBLY OF MANITOBA
THE STANDING COMMITTEE ON CROWN CORPORATIONS
Wednesday, April 4, 2012
LOCATION – Winnipeg, Manitoba
CHAIRPERSON – Mr. Bidhu Jha (Radisson)
VICE-CHAIRPERSON – Ms. Melanie Wight (Burrows)
ATTENDANCE – 11 QUORUM – 6
Members of the Committee present:
Hon. Mr. Chomiak, Hon. Ms. Marcelino
Messrs. Allum, Cullen, Dewar, Helwer, Jha, Marcelino, Ms. Wight, Mr. Wishart
Substitutions:
Mr. McFadyen for Mrs. Stefanson
APPEARING:
Hon. Jon Gerrard, MLA for River Heights
Mr. Scott Thomson, President and Chief Executive Officer, Manitoba Hydro
Mr. Bill Fraser, Chair, Manitoba Hydro-Electric Board
MATTERS UNDER CONSIDERATION:
Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2008
Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2009
Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2010
Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2011
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Madam Vice-Chairperson: Good evening. Will the Standing Committee on Crown Corporations please come to order.
Your first item of business is the election of a Chairperson. Are there any nominations for this position?
Mr. Gregory Dewar (Selkirk): I nominate Mr. Jha.
Madam Vice-Chairperson: Mr. Jha has been nominated. Are there any other nominations?
Hearing no other nominations, Mr. Jha, will you please take the Chair.
Mr. Chairperson: Good evening and welcome everyone here today to this committee meeting.
The meeting has been called to order and the following reports are to be considered: Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2008; Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2009; Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2010; Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31, 2001–2011.
Before we get started, are there any suggestions from the committee as to how long are we going to sit this evening?
Mr. Cliff Cullen (Spruce Woods): I see we’re having a–looks like a presentation tonight. Just wondering if we could maybe sit till 8 o’clock and then review things at that time and see how the questioning’s going.
Mr. Chairperson: So 10 o’clock has been suggested. Is it agreed by the committee?
An Honourable Member: 8 o’clock.
Mr. Chairperson: 8 o’clock, sorry. Well, that’s good. Okay. Sorry about that.
Now that we have set the time, does the honourable minister wish to make an opening statement to introduce the officials in attendance?
Hon. Dave Chomiak (Minister charged with the administration of The Manitoba Hydro Act): I would, with the committee’s indulgence, like to take a few minutes to introduce the gentlemen that are appearing before us this evening, as well as to make some brief opening remarks. And then I’ll be asking leave of the committee to allow the new president to do the usual course of action in this committee, and that is to provide a PowerPoint presentation for committee members, then allow for questioning after, if that’s appropriate.
So to start–and I see I have rapt attention of members around the table and the millions of people that will be reading this in Hansard as we go on–I’d like to introduce to the committee Bill Fraser, our new chairperson, who’s well known to many people in this committee. He served on the Hydro board now for six years, has previously served as the provincial comptroller. He joined the Manitoba Telephone System in 1986 as vice-president of finance and became president and CEO of MTS in 1994. He’s a chartered accountant and is widely respected in both the telecommunications and chartered accounting industries. He also served as the vice-chair of the board of the St. Boniface Hospital Foundation.
It also seems appropriate to note that six new members have been appointed to the Manitoba Hydro board since we last met. They are: David Crate, Chief, Fisher River Cree Nation; Tina Keeper, actor, former Member of Parliament; Eugene Kostyra, former Manitoba Finance Minister; Dudley Thompson, principal architect, Prairie Architects; Larry Vickar, president, Vickar Community Chevrolet; and Frank Whitehead, MLA, The Pas. These are the new members who join Mr. Husiak, John Loxley, Michael Spence, and Leslie Turnbull on the Hydro board.
In January, we had the honour of announcing the appointment of a new president and CEO for Manitoba Hydro following an extensive and thorough selection process. Scott Thomson is a chartered accountant who was previously executive vice-president, Finance, Regulatory Affairs and Energy Supply, and chief financial officer with FortisBC Holdings Inc., a major natural gas and electric utility in British Columbia. Scott started in the energy utility industry in 1999 with Terasen Gas. Prior to that, Scott worked with the accounting firms of Clarkson Gordon and Ernst & Young, LLP. As you can appreciate, since he’s only been in his new position for less than eight weeks, Scott is continuing to meet people at Manitoba Hydro and in the community. And to fully appreciate the challenges and opportunities ahead, he takes on a mantle of leadership at Manitoba’s largest, most diverse, well-loved and watched over Crown corporation, Manitoba Hydro.
I would also like to recognize someone who’s not here today, that being the former Hydro president and CEO, Bob Brennan. The province has benefited from the leadership skills of Bob for 21 years as he was president at Hydro. His longevity in that position is unlikely to be repeated–sorry Scott. But no more–but more than that, Bob oversaw a period of growth, expansion and achievement at Manitoba Hydro that earned the corporation a national reputation for energy conservation programs, low rates, great service. So I’d like to publicly thank Bob for his significant contributions to the energy sector in this province.
Mr. Chairperson, the–that concludes my opening comments.
Mr. Chairperson: We thank the honourable minister.
Now, before we ask the opposition for an opening statement, I would like to request, are there any suggestions as to which order we should consider the reports?
Mr. Cullen: It’s been normal practice here in committee that we just review the reports in a global fashion, and I’m–hope that would be the undertaking of the committee to review them in that fashion again tonight.
Mr. Chairperson: Agreed? [Agreed]
Thank you. Now, does the official–yes, Mr. Cullen? Sorry.
Committee Substitution
Mr. Cullen: Yes, if I may, Mr. Chair, first of all, in terms of committee members tonight, I wonder if it should just be noted if we could have Mrs. Stefanson removed and have Mr. McFadyen inputted in her place in terms of the committee tonight, just for the evening tonight.
Mr. Chairperson: Is this all right for the committee to–if Mr. McFadyen is the replacement? [Agreed]
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Mr. Chairperson: Thank you. Now, does the critic of the official opposition have an opening statement?
* (18:10)
Mr. Hugh McFadyen (Leader of the Official Opposition): I want to just begin by seconding the minister’s comments and words of thanks to Bob Brennan for his years of dedicated service to our province and to Manitoba Hydro in particular. We certainly had the opportunity to work with him both from the context of government and opposition, and he put a very significant amount of time into the job of leading the corporation over the years, participated fully in some healthy matters of policy that we debated at committee, and we certainly wish him well. And I want to just have it reflected that we certainly support the minister’s words of thanks to Mr. Brennan.
I would also just want to note that just in the gallery today is another former president and CEO of Manitoba Hydro, Len Bateman, who just joined us, somebody else who served the corporation with distinction and the province with distinction for many years. And welcome, Mr. Bateman, to tonight’s proceedings.
And I also want to just pick up on what the minister said in welcoming the new chairman, Bill Fraser, who we respect immensely, and certainly wish well in undertaking the new challenges with Manitoba Hydro, and also welcome you, Mr. Thomson, as the new president and CEO, and certainly welcome the background and experience that you bring to the job and your commitment to leadership of the corporation in the years ahead. And also just make note of the new rookie minister who’s taken on the responsibility here, and just say that it’s a pleasure to be with him again tonight, as it always is.
And just to say that with some of the changes in leadership at Manitoba Hydro–which is a healthy process, from time to time–we view it as an opportunity to perhaps challenge some of the assumptions and take a fresh look at some of the assumptions that have been in place now for many years. Don’t say that with a political view, but a view that it’s a healthy opportunity for the corporation to take a fresh look at where it stands today, where it’s come from and where it plans to go into the future, and certainly encourage you to challenge assumptions and to vigorously base decisions on facts and evidence and your best judgment as to what’s in the interests of the corporation, the province, going forward.
With that, we will have questions following the opening presentation, but again want to just welcome you, thank you for taking on the challenge. As the minister said, it is a watched-over and cherished corporation in our province, so you arrive here at an interesting time in the corporation’s history, and we wish you nothing but success as you go forward. Thank you.
Mr. Chairperson: We thank the member.
I understand the representative from Manitoba Hydro-Electric Board wish to include a PowerPoint presentation as part of their statement to the committee. Is there leave from the committee to allow PowerPoint presentation? [Agreed]
Please proceed.
Mr. Scott Thomson (President and Chief Executive Officer, Manitoba Hydro): Thank you, Mr. Chair, and committee members. It’s my pleasure to be representing Manitoba Hydro in this, my first appearance before this committee. As the minister indicated, I started my new role in mid-February, and I’ve been busy getting oriented to the Manitoba Hydro organization, touring some of our facilities in the–at least in the south of the province at this point, meeting with our employees and key stakeholders in the community.
Tonight I’ve prepared a presentation that provides a high-level overview of the company’s current state of affairs and outlook, including some of the challenges that we’re facing, and I’ll be pleased to respond to any questions that you have following my presentation.
Just to give you an overview of the areas that I want to touch on tonight, briefly, some corporate profile and background. I’ll delve into the area of finance, rates, interactions with the PUB, our export initiatives, and then talk to some operational areas, including generation, the wind projects, transmission operations and capital and a little bit about our aboriginal relation activities, and I’ll close with some talk about our demand-side management programs.
A snapshot–current snapshot at the end of February, shortly after I took over my role–just shy of 6,500 employees currently with the organization. About 4,400 of those deal with operating activities, and the balance focused on capital construction and initiatives. That’s down somewhat from the prior year.
We’ve–we serve just over 542,000 electric customers and 267,000 natural gas customers. We export extraprovincially into three wholesale markets in Canada and the Midwest US through the MISO, and currently enjoy an electric rate structure that is the lowest in North America.
I’m sure many of you are familiar with the–some of the detail in this chart so I won’t belabour it, but the bulk of our generation is in the north on the Nelson River: 80 per cent of our generating capacity in the stations that you see are the red dots across the northern part of the province, 12 per cent of generation comes along the Winnipeg River systems, 6 Saskatchewan, and then we pick up about 1 per cent through wind procurement and thermal and imports of natural gas and coal sites at Brandon. In terms of our capacity to export, we’ve got 2,175 megawatts of capacity into the US market, 150 into Saskatchewan and west, and about 200 megawatts into Ontario.
I’ll touch briefly at an overview level here on key financial statistics, but I’ll get a little bit more into detail on this in the finance section. At the end of fiscal ’12, our plant and service and capital work in process is approximately $11.8 billion, and the capital program going forward will add to that through the next decade, and I’ve got an outlook for the 10-year period.
What I’d–some of the thing I’d like to draw your attention to on this slide, and there’s been discussion about the financial position of the company and the fact that we are in the best position that we’ve been in historically from a financial capacity perspective in terms of–I’ll just see where we were at the end of fiscal ’11 with an equity component of our capital structure at 27 per cent, and we anticipate being at about 26 per cent at the end of the most recently completed fiscal year.
Next year, the capital ratio drops to 20 per cent and there’s–that’s a function of a couple of things. The most significant component is the adoption of international financial reporting standards, which we plan to adopt this fiscal year. As a consequence of the new accounting rules, we’ll derecognize rate-regulated assets and pension–our pension position, effective the start of the fiscal year. And that contributes to 4 per cent of that drop. The balance is because of the capital expenditure program: we’re adding to our rate base and our capital work-in-progress, we are adding to–anticipating adding to our retained earnings position in absolute terms, after you adjust for the changes in the accounting rules. But it’s because of the capital program that we’re seeing a change. And we do project that to decline in percentage terms over the course of the next decade before recovering in the future.
Just a comparison of where we stand at the end of the 2011 calendar in relation to the lowest cost jurisdictions in North America for electricity rates: we do continue to enjoy the lowest average rate structure in North America, and if–and in comparison you’ll see–if I can get this pointer to work here–we’ve got the major hydro jurisdictions being Québec, BC and Washington state, and then, you know, the balance–a lot of that generation is coal-based generation.
* (18:20)
The last slide in this section deals with our capital expenditure program. You’ll see a ramp-up in our capital expenditures over the course of the decade. That’s really driven by meeting our demand–our forecast demand load growth of new domestic demand as well as reliability requirements and refurbishment of aging infrastructure and replacement. And that’s what we’re seeing across the industry is an ongoing refurbishment of aging plant, and that’s contributing to this picture.
Move into the finance section. Underpinning–one of the key assumptions underpinning our outlook–our financial outlook is that the load–our load will grow in Manitoba at an average rate of about 1.6 per cent a year after giving effect to the demand-side management initiatives that we’ve got in place. This is similar to what we’ve experienced over the past 10 years. In terms of capacity requirements and peak demand, that’s about an 80‑megawatt addition every year, and based on this we anticipate needing new generation in our supply stack by about 2020-2021. And that gives effect to the addition that we will get this year from the Wuskwatim project, which is a 200-megawatt hydro plant.
So, near-term, just talk a little bit about what we–our actual financial results and our anticipated for the current fiscal year just ended and then an outlook over the next two-year period. We’ve included the two-year forecast because that coincides with the rate application that we’ll be making to the Public Utilities Board later this spring.
Last year, in fiscal ’11, our net income level was $150 million. We had originally applied for and had interim rate increases on the electricity side of 2.9 per cent in fiscal ’11 and 2 per cent in ’12. Subsequently, in January of this year, the final rates were made permanent and there was a rollback of 1 per cent on the–effective the beginning of April 2010, so that 2.9 per cent dropped to 1.9 per cent and we were ordered to remove that from revenues and set it aside in a deferral account. So on the net income line, under the most recently ended fiscal year here, that $52-million forecast reflects the elimination of that $23-million–the effect of the 1 per cent rate rollback.
Now, it’s our intention to seek recovery of that in our general rate application, and I’ll speak a little bit more about that momentarily. If we’re successful in obtaining that relief in our general rate application, then we’re anticipating a forecast net income in fiscal ’13 of $40 million. Absent recovery of that 1 per cent rate rollback, we’d be looking at consolidated earnings–all else being equal–of $17 million, which is just over break-even from our electricity operations after giving effect to the earnings from–anticipated from natural gas and our international activities.
Wanted to share this slide with you because it–in significant measure, the change in our extraprovincial revenues have had an impact on our outlook moving forward over the next few years. We’ve–this graph depicts our extraprovincial sales net of water rentals, fuel and power purchases, so kind of the net contribution after serving our domestic load and the costs of serving that load. We would anticipate in the ordinary course that over time when we’re not adding new generation facilities that the amount of our extraprovincial sales would decline, the volume of sales, because we’re displacing the export sales with our domestic demand growth, so that’s what you’re seeing in part through this period. But we’ve also experienced a decline in the spot market for electricity, in the MISO market and in other wholesale markets that we participate in.
The rebound, as we look forward through the balance of this decade and into the early ‘20s, reflects two things: one, an anticipated recovery in electricity pricing, as well as the start-up of some of our new export sales contracts that will be driven after we bring the Keeyask project online in–later in this decade.
And then I wanted to show you this slide related to our capital structure outlook, and I wanted to draw your attention to a couple of things. You’ll see that in the period leading up to this year we’ve had a steady increase in the retained earnings in the corporation. In 2013, I mentioned earlier that we’ll see a decline in our equity ratio and our capital structure.
But a significant component of this in absolute terms is driven by the writedown of our rate-regulated assets, so it’s the–largely a function of the investment that we’ve made in Power Smart activities over the past two decades that we have not yet amortized. And under international financial reporting standards, we have to derecognize those as well as recognize the current position of the pension plan all at one time. Under Canadian GAAP, adjustments and market values of pension assets are smoothed over a number of years. So there’s $375 million associated with a direct charge to retained earnings on rate-regulated assets being derecognized, and then another $205 million anticipated on–related to pensions that go through other accumulated comprehensive income.
In absolute terms, once you adjust for those accounting adjustments, we will see the earnings continue to contribute to the absolute value of our retained earnings. But because of the investment that we’d be making in capital over the decade that I reflected on the previous slide, our equity ratio will decline from the current level. The good news is we are well positioned for this, but it will present a challenge for us as we move forward.
So just to highlight some of the major capital initiatives we’ve–as we move forward through the next rate application forecast period, ’13-14, you’ll see the Wuskwatim project, which I’ll speak to in a little more detail momentarily, which will come into service later this spring. The bulk of the expenditures on that project have been made and the wrap-up and demobilization of that project occur this year.
Keeyask, which has an overall budget estimate of about $5.6 billion, the expenditures related to that are really the ongoing activities that are required for environmental studies, pre-work activity, site preparation, roads and that sort of thing that need to be put in place–the infrastructure that we need to put in place in order to get to the site to build the project. So the absolute dollar amounts are significant, but in relation to the overall project size it’s still the early period of both Keeyask and Conawapa.
The Pointe du Bois Spillway project will ramp up this year and next, and the overall cost of that is estimated just under $400 million. And then the final line, which is all other capital which relates to the cost of serving new customer additions, refurbishing old plant, reliability expenditures, et cetera, you’ll see that from ’11-12 and into the current fiscal year we’ve been on a declining track. There’s been a concerted effort to review the capital plans, prioritize expenditures associated with recurring capital and replacement capital and defer those expenditures where it’s safe to do so. And that program will continue. Our current estimate is that we’re going to have to start spending some of the money that we’ve been able to manage forward in fiscal ’14. But that program will go on, and my hope is that we’ll be able to manage that down as well.
* (18:30)
Talking a little bit about rates, I thought this slide might be useful. If we go back over the last decade, to 2001, the corporation has been successful in managing its–sorry, I’m going to try and back up here. I’ll just– again, I’ll just highlight the one item I didn’t talk about on this slide was Bipole III, but I’ve got several slides later in the presentation.
An Honourable Member: It’s not going to come up.
Mr. Thomson: No?
An Honourable Member: Okay, we’re going to let that one slide.
Mr. Thomson: Okay. But we will be in a period of ramp-up of expenditures on that and I’ll get into the details behind that program as–later in the presentation.
So, over the course of the past decade, we have managed rate increases below the level of CPI for electric rate consumers in the province. There were some rate reductions early in the decade and then, since then, we’ve been able to manage it at a level below.
And on the natural gas side of things, what we’ve–what we see right now is the lowest average residential bills that we’ve been able to deliver in over a decade. These are nominal dollars, so, in real terms, they’ve declined further. The lion’s share of this is driven by commodity price of natural gas and a lot of factors that are driving that.
Shale gas production has brought an awful–brought a lot of new production onto the market. A few years ago, we–everyone anticipated that we’d be importing liquefied natural gas to meet the growing demand in North America, and now, we’re building export terminals on–planning to build export terminals on the West Coast. So that’s helped to depress things.
We’ve had a warmer than normal winter and we’ve got a soft US economy, so the demand for natural gas for electricity generation is off or had been off. What we are actually seeing more recently in the US is that electric generation with natural gas is coming back. There’s been about a 35 per cent increase in the demand for gas first quarter of 2012 versus first quarter of last year. It’s been masked by the demand destruction on the heating load through the winter and high storage levels. But, if trends continue, I think we’re going to see that start to reverse as we move later into the year. And then, if we have a hot summer, that will put more pressure on prices going forth.
The current spot market–people, I think, tend to look at natural gas prices and what’s on the spot market right now and say, oh, gas prices are super low, and they are, but they’re below the current cost of production and that’s a function of this supply-demand imbalance at the moment. And, as we look forward at gas prices going forward, the good news on–for our electric business, is that, that we’ll see some pressure on gas prices going forward and the–and hopefully the export prices that we can attract.
Just a couple of comparisons where we stack up on rates: residential bills–this is a typical heat-load customer, so somebody that uses electricity to heat as well as for general consumption–2,000 kilowatt hours per month, and we come in in the most favourable position based on our current rates. If we were looking at a non-heat-load customer, Québec stacks up slightly lower than Manitoba right now and that’s a function of the basic fix charge more than anything else, and the lower consumption levels. For commercial customers with a load of 10,000 kilowatt hours, this is substantial price advantage for our customers in the province and we anticipate that that will continue.
And then, one final just comparison for your information: If we go back to 2005, I wanted to show you this because it–in absolute terms, if we were–if we use current interim approved rates for Manitoba Hydro and set that as the base overall, at a hundred per cent, how we stack up across the various jurisdictions: about 20 per cent less than BC Hydro, and BC Hydro is looking at sustained increases at plus 5 per cent a year going forward; Hydro-Québec, we’re below Hydro-Québec although the absolute rate of change at Hydro-Québec has been somewhat lower, but they started in a higher position in the middle of the last decade; and then a substantial price advantage over the balance of the jurisdictions in the country.
Just a few comments on the current state of our regulatory applications, and I’ll go back to our filing in December of 2009 for rates effective ’10 and ’11, where we had applied for a 2.9 per cent increase, and our rate strategy was really predicated on trying to maintain rate increases at or below that level over the long haul. We finally got approval–or final rates approved in January of this year, so over two years after the initial application, and with the rollback effect, to make our 2.9 per cent effective 1.9 and the interim rate made permanent at 2 per cent in 2011.
With respect to the rate rollback, I mentioned this a little earlier that the cumulative effect of that over the two years of the rate period was $23 million at the end of the fiscal year. So, as part of our–we filed last Friday an interim rate application seeking relief allowing us to bring that $23 million back into revenues and an increase effective April 1 of a further three and a half per cent, and our general rate application is–intends to build another three and a half per cent on top of that, effective April 2013.
So I have to admit to being impressed with the speed at which the PUB looked at our application, because we filed it at 5 o’clock on Friday afternoon and we got a decision Saturday afternoon. The interim order denied the $23-million request and rolled back the three and a half per cent to 2 per cent on an interim basis, effective April 1.
Now the earnings outlook that I had shown you earlier in the presentation assumed that we would get both the 1 per cent or the $23 million brought back into earnings as well as the full three and a half per cent. So our–it is our intent before the end of May to file our general rate application and outline the rationale for why we need these increases at this level.
But I thought it might be helpful for the committee if I gave you an overview of what the net effect of all of this is. I mentioned that the strategy had been based–or we had anticipated seeking 2.9 per cent rate increases in the last rate–last general rate application and a further 2.9 per cent a year in the current general rate application.
What ultimately got approved, as I mentioned, was the 1.9 and the 2, and our current proposal is to reinstate the 1 per cent with effect back to 2011–or 2010-11 and then the further three and a half per cent. On a cumulative absolute basis, that’s a–it’s almost a wash. In fact, on a present value basis, when you look at the timing of the increases, the overall revenue that we’ll get is about $11 million less than we would have gotten if we’d just got the 2.9 per cent a year rate increase that we had originally been seeking.
* (18:40)
I’d like to talk a little bit about exports, and just a snapshot here. We’re currently able to sell all available surplus energy at market prices subject to transmission constraints and limits on our system and on the US side of the line. There continues to be demand for–long-term demand for clean, hydroelectric supplies. The slow US economy has reduced and deferred some of the urgency of this, and, in order to maximize the value of our future generation, we will be looking at additional import capacity as well as tie lines to the US.
So the factors that limit our–that can place limits on our exports, again, the availability of surplus power, and as we displace through domestic load growth, that will certainly limit our ability to export over the near term. And then the firm and–the availability of firm and non-firm transmission capacity into the MISO market, there are also some preference rules for full MISO members, and Manitoba Hydro is not one where we’re a MISO participant, but generation in the MISO area gets precedence for available capacity over ours. So we have a strategy in place to attempt to control as much firm transmission capacity as we can in order to have access to the market.
Overall, I think you’re familiar with the various power export contracts that we’ve entered into over the last couple of years, and I won’t belabour these slides, but we’ve signed agreements for 375 and 25 megawatt system power sales for–to Northern States Power for the period 2015 to 2025, and a further on-peak energy power sale of 125 megawatts for the period 2021 through ’25, and that’s new sales contingent on the availability of new generation. So if–the contract’s structured so that if we do build Keeyask then those sales will–those contracts will be firmed up. If we’re–if we were delayed we’re not obligated to deliver if we don’t have the capacity to deliver so that our exposure’s limited there.
Minnesota Power, again, a similar sort of arrangement: 250 megawatts for the period 2020 to 2035. Again, this one is conditional on building new generation at the Keeyask and subsequent. And then finally, the Wisconsin Public Service contract, which is a hundred million dollar–or, sorry, a hundred-megawatt sale for the period 2021 to ’27. We’ve also signed a term sheet extension for an additional 400–up to a hundred–400 megawatts of capacity for the term 2025 to’35, which would be dependent on the Conawapa project. These new generation projects are essential elements of our preferred development plan going forward.
And then I’d like to talk a little bit about Canadian sales. Revenues of our extraprovincial sales, this year we’re looking at about $370 million in total, $50 million of which are in Canada, and about 75 per cent of that is to Ontario, with the balance being through Saskatchewan and into Alberta.
SaskPower has identified a requirement for over 4,100 megawatts of new capacity by 2030 to replace aging generation fleet and to meet their load growth. They’ve got a–their resource development projects, uranium mines in the north and potash in the south. So there’s an opportunity there to capitalize on that. They’ve announced a number of initiatives, including carbon sequestration demonstration projects, and they’re pursuing wind and natural gas supplies as well. But they have identified a desire to look at longer term accessing, long-term clean energy from us. The province signed an MOU in February of last year with Saskatchewan, and we’ve been working with SaskPower co-operatively to investigate what opportunities may exist over the longer term.
Shifting onto our generation activities, at a high level, our strategy around generation is really maximizing the availability and the output of our existing hydro facilities and then, as it relates to new generation, minimizing flooding and the environmental impacts of our projects that we’re planning to build, and doing those new projects, which are based in the north, in co-operation and partnership arrangements with local communities and First Nations that are impacted by the development.
The three key projects, again, are: Wuskwatim, which comes–we’re anticipating first power in mid-June of this year, bringing on 200 megawatts; Keeyask, coming into service in 2019, which will bring on just under 700 megawatts of capacity; and then down the road, Conawapa in ’24-25, and that’s a–that’ll be the largest generating station that we will have built, at that time, at 1,485 megawatts.
There’s limited environmental impact in terms of flood impact. The bulk of the flooding occurs within the existing river ways, so it will–these projects have been designed to minimize the impact on local communities, and the environment in general.
At a high level, Wuskwatim, as I’d said, we’re in the commissioning phase of this project now; we’re substantially complete. The first unit is scheduled in service mid-June, with the balance into the middle of the fall. We anticipate having the three units up and running by mid-October. There’s a picture there of the installation of the unit, two-turbine, at the bottom of the picture.
In total, we–the total number of project hires on this project were over 5,700, and almost 2,200 of those were Aboriginal people, self-declared Aboriginal people. As of January 31, the construction activity had ramped way back and there were still 268 workers on the site. And, again, relatively the same proportion, about 85 of those, are Aboriginal people–were continuing to work on the project.
This is an artist’s rendering of the Keeyask generating station. Our earliest possible in-service date on this project would be 2019. To meet this date, we’ll have to start construction in 2014. We’ve signed a joint Keeyask development agreement that outlines partnership arrangements in 2009 with the Tataskweyak Cree Nation, Fox Lake, War Lake and the York Factory Cree nations.
In addition, we’ve signed adverse effects agreements, which deal with potential adverse effects for the partners in the joint development agreement, activity that’s commenced, primarily related to infrastructure, access road developments, the starter camp, which we started building in January of this year.
In December of 2011, we filed the environmental act proposal form; the federal-provincial environmental assessment process is now under way, and we are anticipating a thorough needs-for and alternatives-to process prior to finalizing the authorization for construction to commence.
* (18:50)
And then the–finally the–a rendering of the Conawapa Generating Station. As I’d mentioned, the earliest in-service date on this one would be 2024, likely 2025 now. That would–it’s about a nine-year construction time frame, given the scope and scale of the project. This, in our outlook of our supply stack, this will be the lowest cost-generation option to the company going out into that time frame.
Talk a little bit about our two–the two wind projects, the St. Leon wind farm which is owned and operated by Algonquin Power. This project commenced commercial operations in June of 2006 at 99 megawatts in the first phase. We’ve got a power purchase agreement that expires in 2026 and then a second phase of this project that added an additional 10 turbines, which brings the overall installed capacity up to 120 megawatts, just over 120 megawatts. We didn’t need to add any incremental transmission facilities to take power from the expansion of this project. So it’s additional clean power that we can bring onto the system.
The St. Joseph’s wind farm, owned and operated by Pattern Energy, has 60 turbines installed, a total capacity of 138 megawatts. Commercial operation started last spring. This one was more unique in that Hydro provided a construction financing loan for it. It’s repayable over 20 years with interest and can set off against the power purchase agreement. So the exposure on the funding there is–has been managed that way.
On the transmission system–we are getting towards the end of the presentation–I want to talk to you a bit about Bipole III, the Bipole III plan. You know, I think you’re all quite familiar with this project. The project itself is now at–sorry, a 1,384 kilometre HVDC transmission line, 500 kilovolts. It encompasses two 2,000-megawatt converters stations, one in the north–and I’ll probably butcher the pronunciation of this–but Keewatinoow and the Riel converter station.
Work is–several works have commenced on the Riel project. There’s a subcomponent of the reliability related to that that ties the Dorsey Converter Station on the west side of town to the Riel station that’s independent of the converter component of the project that relates to the Bipole III. The Clean Environment Commission has initiated a process, and intervener registrations are ongoing right now. We anticipate that there will–the hearing will commence in the fall with a–our licence to follow late in the year or early January. And the planned in-service date for Bipole III is 2017.
First and foremost, Bipole III is a reliability and security of supply project. The proximity of the existing two bipole lines in the Interlake corridor exposes us to–and leaves us vulnerable to extreme weather events we’ve–which we have experienced in the past. We bring about 70 per cent of our power through the existing Bipole I and II lines from the north out of the 80 per cent of our total, and it all comes through a single converter station at Dorsey.
A failure of the Bipole I and II lines in a remote location could take six to eight weeks to bring back into service. Many of you will probably remember when the storm in September of 1996–I’ve seen the video on it. I wasn’t here to experience it myself, but we lost 19 towers just north of the Dorsey Converter Station. And it was determined to be a microburst storm that knocked the towers down, and we were able to–the corporation was able to respond to that quite rapidly and bring some temporary measures in. But we benefited from the fact that it was in the shoulder season. We weren’t in the high-demand cooling period and we weren’t into the heating period. Absent that, we could’ve had real trouble. And, just with the growth of the system and the load on our system and our capacity now, it exacerbates that situation.
If we had a catastrophic failure at Dorsey, depending on the nature of that, it could take up to two to three years to bring it fully back into service. We did have a storm last year that damaged the facilities and fortunately it wasn’t significant. It didn’t have any significant impact on us. But if we lost either of the lines or the station in the winter period, we’d be looking at rolling blackouts through southern Manitoba until we could bring it back on stream. So, the project is to enhance the reliability of our system and to protect security of supply in southern Manitoba.
In terms of the process and where we stand with the process, there have been four rounds of stakeholder meetings, community open houses, landholder information centres. We’ve had in excess of 400 meetings in various communities through the period from 2008 up until this past year. We filed the environmental impact statement in December of 2011, and, as I mentioned, we anticipate hearings with the Clean Environment Commission to–in the–start in September and we’re hopeful that we’ll get a determination by the end of the year or into early January.
Whoops. Let me–I’ll just back up here briefly. Actually, I think we’re–kind of spoke to the things that I wanted to on this one. The current budget for the project is just under $3.3 billion. Of this, about 38 per cent relates to the transmission line itself with 1.26 billion, the converter stations 1.8 and then collector lines up north to gather the power about 100–just under $200 million. Life-to-date expenditures at the end of January were about $150 million, split between the transmission line component and converter stations primarily. Internally, we’ve utilized about 150 person-years of labour towards the project to this point.
I’d like to talk a little bit about Aboriginal activities with our Aboriginal partners and the impacts of our operations on northern communities. Over about the past 100 years, hydroelectric development in Manitoba has caused significant physical, economic, social and cultural impacts on Aboriginal peoples along project-impacted waterways. Hydro’s acknowledged its obligation to address the past effects of its project including–projects including those that it inherited through acquisition over the years. And we recognize that our future as a producer and exporter of hydroelectric power will require us to address these past effects and build–continue to strengthen the relationships that we have with Aboriginal people in the province.
Over the past two decades, we’ve worked with First Nations and other Aboriginal groups and resource harvesters to settle claims. In total, we’ve entered into more than 60 major agreements in that time frame.
In 20–fiscal ’13, some of the nature of some of the work that we’ll be doing in this area continue to address shoreline erosion on reserves located on Split Lake, for Tataskweyak and York Factory First Nations, the South Indian Lake area. We’re working on an accord with the Sagkeeng First Nation and anticipate on finalization that we’ll also be doing work this year on the Winnipeg River shoreline enhancement there.
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Some other areas affected and that–areas of focus will be debris management on waterways including Cedar Lake, Cross Lake, in the Jenpeg generating station forebay and on Split Lake and South Indian Lake, and we may be doing work on the Burntwood River this year as well.
The overall management framework is–there was the Northern Flood Agreement that was put in place in the ’70s, but really was addressed through comprehensive implementation agreements with four of the five affected First Nations, being Norway House, Tataskweyak, York Factory, and Nelson House. The remaining outstanding band is the Cross Lake First Nation. We’re working effectively with them, but we never ratified a comprehensive implementation agreement with them. We’ve got, as I mentioned, agreements in place with most impacted communities now, and in, over the past 47 years, the total expenditures on mitigation and dealing with adverse effects is almost $800 million. It’s a significant amount of money obviously, but it represents both good value for Manitoba ratepayers as well as addressing issues that really needed to be addressed.
Some ongoing initiatives that we’ve got–we’ve targeted–we’ve got targeted employment levels for Aboriginal people within Manitoba Hydro that are to represent the level in our workforce that would mirror what we see in the population of the province so, and we’ve largely met the targets. Currently, about 16 per cent of our overall workforce is self-declared Aboriginal, and almost 41 per cent of our northern workforce are Aboriginal peoples. We’ve achieved these employment targets largely as a result of targeted recruitment efforts and programs designed to attract and retrain qualified Aboriginal candidates into our workforce.
We also do a lot of business with Aboriginal companies in the province. We’ve developed a northern purchasing policy that gives weight to the participation of Aboriginal companies and/or at least Aboriginal employment on tenders. So other things being equal, or approximately equal, in terms of cost, we’re–we will give preference to bidders who have Aboriginal employees in their workforce or dedicated to the project. And over the last three to four years we’ve averaged about $50 million in procurement through Aboriginal businesses in the province, which is about 10 per cent on average of the procurement that we’re doing here.
I’m going to finish with just some highlights of our Power Smart program and some of the history. We were instrumental in–Manitoba Hydro was instrumental in developing demand-side programs in Canada back in the early ’90s, and over that time frame to date the company’s invested $418 million in demand-side management programs. That’s produced cumulative savings, so an ongoing annualized savings and offset the requirement for generation of over 1,700 gigawatt-hours per year on the electricity side and about 58 million cubic metres per year of natural gas consumption.
It represents that the cost of energy saved is under 2 cents a kilowatt hour and avoided cost is, to date, has been over 4 cents per hour based on imbedded cost of generation. Looking forward over the next 15 years–and appreciate that some of the low-hanging fruit’s been realized on and the nature of the programs will need to change as we move forward–but we anticipate investing another $560 million over the next 15 years. That’s anticipated to generate a further savings, or demand destruction of avoided demand, of 1,944 gigawatt hours per year and–I think I’ve got the, yes, the gas side on this slide–almost a hundred million cubic metres of natural gas. Some of the achievements would have occurred anyways over time.
So I–if I look at this on a cumulative basis over the entire time frame, we’ve invested almost a billion dollars. The net anticipated savings or avoided demand in 2026–not cumulative over that period, but actual avoided demand based on demand outlook–would be almost 3,300 gigawatt hours a year. And to put that in context, if we compared that to the Conawapa Generating Station, it represents about 73 per cent of the capacity. So we’ve got a project that we’ll build 15 years out that’s going to bring on 1,500 megawatts of capacity at a projected cost of $7.8 billion, and we’ve gotten three-quarters of that benefit by investing a billion dollars over time. So it’s been good value for our customers, and we will continue to maintain a focus on that going forward.
On the gas side, the savings realized represent–or–and anticipated are the equivalent of taking about half a million cars off the road by 2026.
And I’ll end there. I apologize for taking as much time as I have of the committee, but.
Mr. Chairperson: Thank you. Now the floor is open for questions.
Mr. McFadyen: I want to thank you, Mr. Thomson, for the presentation and again welcome you. I think it’s–what, six weeks on the job so far? So we’re happy that you could come and spend some time with this committee at such an early stage in your tenure, and so it’s really appreciated.
The–there’s, I think, the consensus in the province that Hydro has really done great things for the province through its history and continues to do so and reasons to be optimistic about its future. But there are also some reasons to be concerned as well that are really–have really started to arise over the last few years, and just in terms of outlook, because a lot of the data just presented is forelooking and based on certain assumptions about things that are going to happen in the future, and inherently that means there’s some uncertainty attached to them. They’re everybody’s best assumptions.
But if you look at where we are right now, the–you’re in the middle of what appears to become a five-year decline in terms of net revenue and the Hydro’s general position after many years of improvement. And if you just use net revenue as the indicator of that–from ’09-010, $164 million in net revenue; ’10-11, dropped to 143, so about a $21‑million year-over-year drop; ’11-12, which just ended, and so I know it’s not completely finalized yet, but you’re looking at a $50-million–$50 million in net revenue after you exclude the 23 that’s–that was dealt with by the PUB, so that’s another drop of about $93 million year over year; and then a projected decline to a loss of $51 million, absent a rate increase, for ’12-13; and then ’13-14, a $58‑million net loss for Hydro in the absence of a rate increase on domestic customers, according to the PUB.
So with a five-year decline, it’s not like it’s a–you know, I think everybody accepts a one-year decline is not something to lose sleep over; two years probably isn’t either; neither is three years. When you look at a five-year pattern of decline in the financial position of the corporation, I wonder if you can just comment on whether there’s reason to be concerned that there’s something structural going on. And I don’t mean necessarily things that are within the control–direct control of Hydro, but within the marketplace and in other–based on other factors, some of which Hydro has control over and some of which it doesn’t. When you look at five years of decline, I’m wondering what that says to you and whether there’s reason to be concerned.
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Mr. Chairperson: Kindly address to me, yes.
Mr. Thomson: I’m getting used to this process.
Mr. Chairperson: Thank you.
Mr. Thomson: The–no, I think, clearly, we’re–corporation’s concerned about the position or the outlook moving forward. There are factors, as you’ve mentioned, that are beyond the company’s control. We cannot affect market pricing. And what we have seen is, while even we’ve got lower in the fiscal year just ended because of warm weather, we’ve had lower domestic revenues, and that’s actually freed up capacity and increased volumes that we’ve exported. The–it would–opportunity sales in terms of volumes, the absolute value of those sales has declined.
So I anticipate that what we’re seeing is a temporal thing. I mean, there are a lot of market factors at play here that are impacting the market price for our opportunity sales of power. And we have seen even the consensus outlook has shifted down, and that’s reflected in our long-term financial forecast numbers that we’ve just updated.
But, having said that, we’ve benefited greatly from the fact that we’ve been able to export power over time. That’s helped us manage our rates. So we’re kind of–we’re seeing the back end of that. We’ve been able to–we benefited from having that capacity and capability of generating revenues that have offset our domestic rates and, absent that, we’re seeing a decline. So we do need to make up the shortfall and we have to find those revenues. So we’re–we’ve undertaken internal programs to restrict discretionary expenditures and manage that to the extent that we can in the near term.
But, you know, we are somewhat dependent on weather, obviously–and I’ve learned that rain’s not a four-letter word in this province like it was in BC. So, you know, is–but in terms of structurally, sort of internal structure, I don’t see that. I mean, there’s good cost control measures in place. So we are–we’re trying to manage the externalities as best we can and capitalize on our ability to generate revenues as best we can.
We do have an obligation to serve, and we’re going to have to serve the growing demand on our system over time. So that’s, you know, although we haven’t–have a significant capital program going forward, we both have to be in a position to meet the load as it comes on our system and the capacity shortfall starts to take place on our system later in this decade, first and foremost, and renew the–and refurbish the existing infrastructure just to maintain the capacity that we have today. And that’s not, you know, unique to Manitoba Hydro where there’s some $300 billion of infrastructure projects been identified by the Canadian gas and electricity association over the next decade just to refurbish plant that’s in existence today.
Mr. McFadyen: I don’t think anybody would have any argument over refurbishing an existing plant.
Certainly, I think the real debate and the issues of the PUB is raising–or they want to deal with future major capital projects. The one we have been focused on, as you will well know by this point, I’m sure, is Bipole III, and it’s really just predicated on concern about the impact on Manitoba ratepayers.
And in the chart that you put up as part of the presentation, you showed quite rightly that historically, particularly in the last 20 years or so, the rates have tended to lag behind CPI, which is a great thing from a consumer perspective, but what we see is that gap closing and now the lines crossing one another. The applications now are in the 3.5 per cent range, which is above wage growth and CPI, and that’s obviously a directional issue that we have concerns about.
And so I’m wondering if you can give some sense as to where you think rates are going. We know what you’ve asked for in the immediate rate applications, but where are they going beyond that, in light of the uncertainties that we have around prices in the export market and, you know, what looks to be a pretty expensive capital program?
Mr. Chairperson: Kindly address the chair.
Mr. Thomson: Sorry. Generally speaking, we’re–what our outlook over the next 10 years, and with regard to the financial position that we find ourselves in or that we anticipate, the leverage that will be built into our capital structure as we build out these major capital projects. And again, it’s not unique to Manitoba Hydro as you enter into a period of capital renewal and growth. The outlook is–and we projected on the order of the level of rate increases that we’re seeking in the current application. So, you know, it’s our desire to maintain low rate increases as we move out, but the nature of a capital intensive business like ours does drive, at periods of high investment, you know, a requirement to go higher.
If we hadn’t made the investments in the ’70s and ’80s for the generation stations up north, we wouldn’t have, you know, sub 6 per cent power today. We’d be looking at, you know, what BC is looking at right now, where rates are six to nine cents residentially, depending on the block that you’re in, with probably 50 per cent increases over the next five years.
Mr. McFadyen: So if I can just ask for–just to clarify the point about the projection going forward, I think you’d–you said that you anticipate that on a go-forward basis, we’d be looking at increases in the order of magnitude of what’s currently being asked for. So are you saying you’re anticipating in the range of 3.5 per cent for a number of years, going forward, going beyond the next two years?
Mr. Thomson: Based on the outlook today and with the revised consensus forecasts on power pricing on the order of what we’ve had, it is going to depend significantly on interest rates, export pricing, and we’ll adjust as we can and respond to those. So we’re certainly not going–trying to get out in front of the curve here, but it is on that order.
Mr. McFadyen: Just on the export sale projections, in that slide, the slide that you put up, there was a–an estimate of about $7 billion in sales from existing contracts or contracts that are in the process, I think, of being negotiated. On the capital expenditure side, it seems to be about $20 billion in planned expenditures over the coming decade or a little bit more than that. So just with a simplistic analysis of $7 billion in export sales and $20 billion in capital expenditures, looks like about a $13-billion gap. And I’m wondering if you can just outline what the forecast is on the export sale side, in particular, and how that gap is going to get closed.
Mr. Thomson: Yes, I think we need to be careful to compare apples to apples. We wouldn’t anticipate funding the $20-billion capital program on the strength of–that for assets that’ll last for a hundred years from export contracts that span the next two decades and components of the next two decades. So we will pay for and recover the cost of those investments over decades, not over the lifetime of the existing export contracts, and we’ll pay for them from domestic sales too.
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I mean, we’re not building them to export. That’s a–we get the benefit of export revenues to help pay for them and allow us to grow into the capacity that we build, because we can’t match our demand to the capacity blocks that we bring on.
So it’s really in the fullness of time, I would expect, that we’ll have additional export revenue contracts as the ones that we’ve entered into expire. So we’ll extend where there’s capacity available, but we’ll also be generating domestic revenues as we grow into the–as our demand grows into the capacity.
Mr. McFadyen: Thanks for that, and that makes sense in terms of the life of the assets. I guess the real issue is, just in light of uncertainty over what may transpire with export sales, there’s a factor there that you need to be mindful of as you’re–as you moving ahead with the major projects, and, as we’ve indicated, probably once or twice, would that be about right? The minister is–has been around the debate for longer than the new present CEO, so I don’t want him to feel as though he’s missed out on anything.
So the project within that mix that we’ve got concerns about is the west-side bipole, the length of the route, the cost associated with the line losses, reliability issues that the engineers have raised. And one thing that–that’s interesting is that there seems to be a shift in the numbers that you’re presenting today from the estimates that we’ve received up until this point.
I think the last–I know Hydro publishes capital expenditure forecasts, CEFs, in connection with all of its capital projects, and I believe–and I stand to be corrected by my colleagues–but certainly, I think up until CEF 11, which was filed just before–I think completed just before Christmas, the estimate for the project was $2.2 billion, and the presentation now says that it’s $3.28 billion, which is a billion-dollar jump. I wonder if you can just comment on that–what appears to be a billion-dollar jump in the cost of the project. [interjection] I should say, the estimated cost of the project. It hasn’t started yet, so he doesn’t know. But the estimates have seemed to have changed dramatically from where they were prior to the new year.
Mr. Thomson: Okay, I’m going to ask forgiveness for it being my 28th day on the job here. I know that there have been changes to the budget estimates over time and some of those relate to scope and routing changes over–and going back a number of years, that the original project hadn’t anticipated–a new southern converter station, for instance. I’d prefer to get back to you on that rather than, you know, misinform you in a response. I’m just–I don’t have the numbers at my fingertips and/or the timing of the, you know, what you’re referring to in terms of pre ’11.
Mr. McFadyen: Sure, and I’ll–just to add to it, there’s been a fair amount of debate and dispute over what the estimate–what is the real estimate for the project. It just, I think, because it’s become so political over the last couple of years. And the–certainly, from 2007 to 2010, the printed estimate, Hydro’s printed estimate, was $2.2 billion. What then happened, probably about a year ago, or maybe a year and a half ago, is that internal documents were leaked which suggested that the cost was a lot higher than $2.2 billion, and those are the documents that are referred to in the PUB order of January 2012. And so the PUB is using 3.2 to 4.1 billion as their estimate, and that’s in, just for ease of reference, order 5/12. And in your document you’ve got $3.2 billion, which is consistent with what PUB is saying.
So the question really goes back to the inconsistency with the capital expenditure forecast CEF 11 that, I think, showed 2.2. So the issue is just–it’s a billion dollars obviously isn’t a rounding error. So if we can get an explanation on that, that would be great.
Mr. Thomson: And, yes, we’ll endeavour to provide additional information on that. I am aware that there have been some scope changes and there are explanatory reasons for the delta over the time.
Mr. McFadyen: Just in relation to the recent rate application, the one that was made on the 30th of March, Friday–late Friday afternoon and then approved on Saturday. I guess we’re–in discussion with colleagues earlier–just curious as to what are the circumstances behind the need for such an urgent application when the factors that are cited as the reasons for needing the increase are things that probably would have been reasonably well-known for a number of months.
Mr. Thomson: Yes. The–part of it’s procedural, but as I’d mentioned earlier in the evening and in my presentation, we didn’t get final determination from the PUB on our last trade application until January, and then we’d sought a variance on that in terms of that order and that was subsequently denied. So, in order to put together an application, obviously, it takes some time, and you need to know what base you’re operating off of. So, we had given the PUB a heads-up that in March, that we would be filing, hopefully, by the end of the month, with a view to being able to establish an interim rate increase if–in order to start the clock, in effect, so that when we filed our general rate increase, it could be effective from the beginning of the fiscal year.
We do need the revenues; we do need the additional funding in our rates. And if–there’s a risk that you run if you delay the application, and the request for interim relief that your permanent relief will start effective the date that you had sought your interim relief. So, to forego the increase over the period of even just the month of April, we’d be looking at a further shortfall of 4 to 5 million dollars in our revenues that we’d forego, and, as I believe we’ll be in a position to demonstrate to the PUB with the full rate application, we need that money. So we had to get it in, and that was the earliest date that we could get it in.
Plus, we–you know, we wanted to give the PUB at least some time to react to it, so that we could get it into our billing system and get the rate increase through.
That was the nature of why we made an urgent request to the PUB.
Mr. McFadyen: Thank you. I’ll just wrap up. Just a couple of questions on the timeline on Bipole III. You will probably be aware of a history, and you’ve made reference in your presentation to the ice storm in–was it ’96 or ’97?–it was ’96–’97. In any event, whenever it was, it’s 15 years and counting now since that ice storm, and the need was identified for a third major DC transmission line. So 13 years under our belt, and having just, as of December, filed the environmental impact statement, I wonder how optimistic you are or what your level of comfort is that this line is actually going to be in service by 2017.
Mr. Thomson: Based on the best advice that I’ve got internally, provided that the environmental review process goes forward and we get a licence by January of next year, the construction schedule should allow us to get it in service for 2017.
Mr. McFadyen: And so, just in terms of–because the timelines have been revised a few times now. There was a deadline of June 2011 to file the environmental impact statement and that slipped to December 2011. And so, is the assumption, then, that you’ll have a licence by, did you say, January of 2013? Is that–
Mr. Thomson: I apologize.
Mr. Chairperson: No problem.
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Mr. Thomson: I’ll get this right by the end of the night.
Mr. Chairperson: Thank you.
Mr. Thomson: Yes, I understand that we’re looking for–we’re anticipating that the process could be conducted and a decision for the licence by January. And internally, we’re looking at how–you know, what we can do in the schedule to manage that.
Mr. McFadyen: Just a question to Mr. Fraser, just in connection with the board’s role in connection with Bipole III.
You’ll be aware, certainly, that the vast preponderance of professional opinion on this project has been that the east side is really the only feasible way to do this–certainly, that’s the engineering advice–and that there have been significant concerns raised, not only about cost financially, but also compromised reliability, practical challenges in getting it built over that kind of a route, and line losses. We’re all happy to see initiatives taken to make the province more efficient in terms of energy usage.
When you look at a line of this length, the line loss associated with it is very, very significant and actually undoes a lot of the work, almost all the work, of the Power Smart program in terms of achieving efficiency. So, in light of all of those very significant engineering and technical concerns, we know–and the government has expressed their view as to why the east side shouldn’t be pursued, and they’ve expressed it in good faith, and that’s not a debate. We just respectfully disagree with the analysis in terms of the costs and benefits.
The question is whether the board will undertake a further review of this decision before allowing this project to go beyond the point of no return and take into account what we believe are the right considerations, which is the financial, engineering and environmental input, as well as the community input from residents on the east side as well as the west side, and take into account all of those factors, and take a fresh look at this decision.
Mr. Bill Fraser (Chair, Manitoba Hydro-Electric Board): Obviously this has been a very contentious issue for the last couple of years and it has been debated politically and publicly. It was debated at the board level as well, extensively and with management, and, as Scott has indicated, there’s something in the order of $150 million that has been spent to date in terms of moving forward with that. And we are in the execution stage of implementing that decision, and there is no intention, at this point in time, to reconsider the discussion that has gone on.
Mr. Chomiak: Just wanting to assist in the process, as the member indicated earlier, that decisions, made in good faith–to help along with the process, the reference to the $3.2 billion actually was made in Crown Corporations last time when Crown Corporations met. I have it here in Hansard, and, in addition, the decision about bipole, as well, was addressed in the same fashion, but the $3.2 million was already addressed in the discourse that took place about the value of per kilometre, per citizen in Manitoba, and the arithmetic associated with that. So I’m sure that Hydro will deliver the–respond to the member but I’ll let him know that such–the exact debate and the numbers were actually debated at this very committee when it last met in May of 2011. Thank you.
Mr. McFadyen: Well, I suspect that that may have been a number that the opposition was putting forward at committee in May but I don’t think it was Hydro’s official position. What we’re interested in is the change in Hydro’s official estimate, and if you could address that, that would be appreciated.
Mr. Reg Helwer (Brandon West): Through you to Mr. Thomson, and I’m new to this too, so I may ask some questions that may seem obvious and I hope you excuse me for that.
In your bipole budget, you talk about total net cost. Net of what?
Mr. Thomson: The total capital costs of the project. So with the various components, I don’t believe there is a net in contribution to it, if that’s what your question relates to.
Mr. Helwer: Through you, Mr. Chair. Usually net implies that something’s been removed. So what’s been removed from this estimate?
Mr. Thomson: Nothing that I’m aware of, but I’ll–I can take an undertaking to investigate that.
Mr. Helwer: Through you, Mr. Chair, to Mr. Thomson. The Bipole III plan, the line that you show going down the west side comes very close to Riding Mountain National Park. Have you had the benefit of visiting that park?
Mr. Thomson: Not as of yet.
Mr. Helwer: Why, I’d certainly encourage you to do so; it’s a gem in Manitoba. It’s our only major national park. It is mountain vegetation unique to Manitoba and, as certainly we see in the boreal forest, unique to Manitoba, but this is a one of its kind. And at this point there are hydro lines running through Riding Mountain National Park, and park staff tell me there that the wildlife actually like those lines because it’s a highway for them. The moose don’t get their antlers caught in the trees, and the elk and such. The cougars that we presently have in the park are able to find them there, perhaps, a little easier.
But–so if we’re able to put hydro lines through such a gem in Manitoba, the national park, why would we not be able to put hydro lines down the east side?
Mr. Chairperson: Mr. Thomson. Mr. Minister.
Mr. Chomiak: Pardon me, Mr. Chairperson, that was just a sigh. I don’t mean to interrupt the proceedings. Sorry, Mr. Chairperson.
Mr. Thomson: There are–it’s physically possible to put a line anywhere, I suppose. But the–as I understand it, and I–as I’ll–I am new here. I’ve done as much reading as I can on getting myself up to speed on the various issues, and bipole in particular. But the decision on routing option has been made, and I am advised that that isn’t an option that’s open to the corporation. So of the remaining options, the west side was selected as being the best option available to us in terms of being able to license it and move forward, and most cost-effective.
Mr. Helwer: Through you to Mr. Thomson: So seeing that–what you have on the map here, do you anticipate the line running through the national park?
Mr. Thomson: I’m not sure–the routing has been selected and that’s what’s been filed in terms of what’s going forward to the Clean Environment Commission review.
And I honestly apologize, but I don’t know all of the details, like where–I know approximately where it runs through the province and the work that’s been done with communities that are impacted by it. But I can’t comment one way or the other. I don’t know. I’m not familiar with the location of the national park.
Mr. Helwer: It’s directly south of Dauphin, so you can see where the line runs south of Dauphin there. It looks to me, pretty distinctly, it’s going to go directly through the park, which I don’t know that you intended that, but nonetheless.
There was a–during the last committee meeting, Mr. Brennan promised Blaine Pedersen to get him a list of municipal governments that have been offered money from funds in the community development initiative along with a dollar amount offered, and the response we did receive was somewhat incomplete. And I’m just wondering, is there a projected length of fund payment, a number of years, one time or annual, and is there a total dollar attached to this fund?
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Mr. Thomson: Do you mind if I confer with–my understanding is that the current proposed program will span a 10-year time frame, and I believe that the funds would be available over that period. I’m not intimately familiar with the details at this point.
Mr. Helwer: Yes, and the dollar amount for the fund is?
Mr. Thomson: I might have that here if you can bear with me for a second. Mr. Chair, my advice is that the program is planned to run 10 years and have funds available of $5 million a year, available to approximately 60 communities.
Mr. Cullen: I just want to go back to the most recent board order, the Public Utilities Board order dated March 31st, and my question is in regard to the $23 million. I know Manitoba Hydro requested that particular money be rolled into the regular account for Manitoba Hydro and obviously the Public Utilities Board didn’t agree with that. So is that $23 million still sitting in a separate account?
Mr. Thomson: Yes. From an accounting perspective, the funds have been–have–the liability, or the deferral account, has been established to capture the $23 million. And it’s been removed from revenues, so it’s sitting as a–in effect, a due–it’s being held in abeyance, in effect, until a final determination of where–how it should be utilized. And as I had mentioned in our general rate application that we’ll file in May, we will seek to have that available to the company for use as revenues again. So we’re–we haven’t given up on that.
The order that we received from the PUB was an interim order, and the language in the order does allow for a further variance to that interim relief that we sought upon filing our general rate application, as more fulsome information is presented. The–appreciate that the interim rate application itself was an abbreviated document and it didn’t include all of the information that we would ordinarily provide in a general rate application. So the board will have an opportunity to examine further evidence and it’s our hope that they’ll opine on it and grant the relief that’s requested.
Mr. Cullen: You indicated the next application is going to be made fairly shortly and I wonder how long you think the board will take in their deliberations. So, until the next order is made, do you have any time frame in terms of when that particular order will be made?
Mr. Thomson: I haven’t had any direct advice on that or indication from the PUB, but looking at where we fall on a calendar and my past experience dealing with general rate applications, I wouldn’t expect that we’d get into the hearing room until the fall. And assuming an orderly review of the application, we probably would be looking at Q4 of fiscal ’13, I’m guessing, before we’d have a final determination. I’m hopeful. I mean, it took two years to get the last one adjudicated, but I’m hopeful that we’re going to be able to deal with this one more quickly than that.
Mr. Cullen: Just changing gears a little bit here, at the end of your presentation you talked about some of your Power Smart initiatives that are under way, and you talked about the, you know, the tremendous offsets that resulted in those programs. And, you know, I guess we’re–what you’re referring to is weighing those incentives, if you will, versus actually putting capital dollars up for investment.
And I’m just wondering if there’s other opportunities that Manitoba Hydro have looked at in terms of initiatives there. You know, other provinces are looking at different metering systems and different rates, demand rates, those types of initiatives that give the consumer a bit of a break in terms of their bill at the end of the day, and I’m wondering if Manitoba Hydro is looking at some of those initiatives in terms of what can save the corporation some demand, and then, you know, with a view to looking at the capital side on the other side.
Mr. Thomson: Yes, there’s an ongoing review of the programs and the–as I’d mentioned in the presentation–the–as we look forward over the next 15 years the nature of the programs will change.
You know, some of the things that I’ve been talking to our staff internally on or how, you know, codes–billing codes for instance can be modified to make construction more energy efficient. I had the benefit of a–kind of a tour of our new building and the innovative design that was used in that, and how as over time both existing buildings can be retrofitted to obtain, you know, reductions in demand or energy–further reductions in energy consumption and then avoid the level of growth and demand for new construction as we move forward.
There–we are looking at what other alternatives are available to us, and we don’t–I believe what you may have been–you alluded to was some of the, you know, rate-making regimes and encouraging use at times of day when power is cheaper and the infrastructure that would be required to do that. On an ongoing basis we’ll continue to look at what options would be available to us and how cost-effective those might be and would look to bring those types of initiatives forward if there was a case to be made for them. There’s no current plans to introduce that at the present time at this stage.
Mr. Cullen: I’m sure the minister and I’ll have an opportunity to discuss some of these as alternative energies down the road during the Estimates process. But, obviously, it’s important from Manitoba Hydro’s perspective as well. You know, when you look at what other jurisdictions are doing in terms of trying to develop biomass and biogas and those types of economies, obviously, Manitoba Hydro has an important role to play there.
And, you know, I’m getting at the capital cost. You know, if we can then defer that capital cost–and I guess that’s what the question is, you know, is Manitoba Hydro looking at the big picture when it comes to these types of resources?
You know, I know you talked about, you know, huge capital investment here over the next decade or so, and I’m trying to get my head around, you know, is there an easier offset? You know, you talked about some of the programs to date being a two-cent-per-kilowatt cost. You know, is Manitoba Hydro actively having a look at those investments that might, you know, save the corporation serious capital investments?
Mr. Chomiak: I just want to take the liberty of responding to the member’s statement. As he indicated, we’ll discuss it in detail in Estimates.
But I had the occasion to, in fact, announce just yesterday that there are–energy-bundling legislation will be brought forward this coming session that will maintain Manitoba’s hydroelectric rates, natural gas rates and MPI rates as the lowest in the country during the course of our tenure in government. That will be brought in in legislation. So we’ll have an opportunity not only to debate in the Legislature, but to debate options. The member will know that Manitoba Hydro’s been rated for the fourth year in a row as the No. 1 energy conservation company in Canada and will continue to look at innovative ways to do that.
In the Department of Energy that I have the honour of being the minister of we’ve, of course–and MAFRI–we looked at a number of biomass energy alternatives including the wind generation and many–and a number of biomass projects, geothermal et cetera. And some of those activities will be highlighted during the upcoming session of the Legislature when we have an opportunity to discuss them in detail.
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But I think the bottom line is that Hydro has been awarded the last four years the No. 1 award in the country by peers–in comparison with peers for energy conservation, and we’ll continue to look both, as a government, in any suggestion that you’re making and as well as suggestion Hydro makes to keep it in the forefront of energy conservation as we go forward.
Mr. Ian Wishart (Portage la Prairie): Through you to Mr. Thomson: Of course, being in charge of Hydro, you are the No. 1 water user in this province, and of course coming off a very high-flow year, and I’m sure they’ve been quick to tell you about all the floods that have occurred in the last year. We’re now looking at somewhat lower levels this particular spring. Have you and your staff had the chance to review the adequacy of the water levels in your current reservoirs and where you’re at regarding that, particularly in light of the fact that we still have two lakes in the province that are beyond flood stage?
Mr. Thomson: Yes, we’re monitoring precipitation and reservoir levels and right now the reservoir levels are in good shape in terms of meeting our requirements moving forward, but the caveat there is that precipitation levels since November have been about 70, I understand–76 per cent of normal, and I’m advised that experience has been in the province that the longer it takes to rain, the less likely it is to rain. So I find myself saying a prayer each night that it’ll rain overnight. But the–you know, I think that we’re not in danger right now, based on the advice I’m getting internally, but it could become a–if it–if we don’t get precipitation through the spring, it will become more and more challenging for us.
Mr. Wishart: I would suggest that there’s a little leftover water in Lake Manitoba you could probably use if you wanted. So I certainly agree with the concern about the–that period of rainfall, but if you look at the year– calendar year for last year, we’re at 113 per cent of normal. So I wouldn’t panic, and, certainly, I hope you manage the reservoirs with in mind the fact that we’re still at something approaching a normal level, not in a drought situation because, as you pointed out, we can go from flood to drought very quickly; we can also go from drought to flood equally quickly.
There wasn’t really a question in that, I guess. I’m–I apologize. But I do hope you keep that in mind. But I had–following that I had some interest in your change in accounting practices as it relates. And I am–some familiarity with the IFRS accounting methods. I’m very curious as to why you chose this year to change, because there’s certainly a–quite a lengthy timeline to adapt the change in accounting methods. What is the reasoning for doing it now?
Mr. Thomson: We–the corporation’s been preparing for some time. The, you know, the move by the Canadian–the CICA to adopt international financial reporting standards has been several years in the making, and the industry in general and–has been preparing for quite some time. General business adopted–were required to–public reporting entities were required to adopt IFRS starting in 2011 calendar. Rate-regulated entities were granted a one-year deferral by the Canadian Accounting Standards Board.
There’s been an enormous debate through the industry and the big four accounting firms lobbying that’s taken place at the International Accounting Standards Board, and I was involved in that myself in my past job. Frankly, the industry doesn’t believe that IFRS that doesn’t recognize regulatory accounting is appropriate. We’ve implored the–both the Canadian Accounting Standards Board to lobby on our behalf with the international body, and they did, to an extent.
Our view is that we ought to be able to recognize regulatory assets. It provides a much better matching. It’s the way rates are generally set and regulated. We–for instance, we recognize that there’s a value to the investment in demand-side management programs, and it spans a number of years. IFRS requires that we write it off in the year that we incur it, and that’s what was driving some of the changes in the graphs that I put.
So, heretofore, the deferral that was allowed to rate-regulated entities in Canada gained us a one-year deferral. And because we have, you know, a fiscal year that starts in April, that deferral period ended last Saturday. So we’ve–up until this past weekend we had no choice.
Now there has been some further development over the weekend, and you may be aware of that. It hasn’t been widely reported in the press, the financial press, and it hasn’t received any reporting in the general press, that the IASB, the international standards board, is considering putting it back on their agenda in–later this year. So the Canadian Accounting Standards Board advised that it may be possible for rate-regulated entities in Canada to take advantage of a further one-year deferral. This–we just got this information on Monday this week.
So we’ve started to look at, internally, what the implications of that might be for doing it. We’ve heard this story before, unfortunately. The–you know, it would–we seem to have a great deal of momentum with the lobbying that we’d done through the Canadian Gas Association that I was quite involved with. And we thought we had gained a lot of traction and that the international board was actually going to recognize–and they went to a vote and it was split. And so they said, well, we can’t decide so we’re just going to ignore it. So Canada decided that they would force the adoption of IFRS effective, you know, with the one-year deferral that they’d put in place.
And based on–we’ve had some discussions with our advisers that we worked with in the corporation, KPMG, and there’s–it looks like it may be back on the table again in June. It may simply just be a one more deferral and one-year further option, and then we adopt it anyways. Or we might gain some traction with the international board and, in my view, they make the right decision this time and they allow us to continue to recognize the value that those expenditures have and the way that our regulators in this country and in the US tend to regulate rates.
So it causes us great problems if we’re forced to derecognize those assets, because the rate setters generally will ignore that, so we’ll end up having a set of regulatory books, a set of external reporting books, and we’ll be forever reconciling between the two, which we’d prefer to avoid. I mean, it makes sense that what you’re reporting publicly is what you use to set your rates as you move forward.
So–sorry, that was a long answer. But the basic premise is that we did–we had adopted it or we were moving to adopt it this year because we had to. We had no choice. We’d get a qualified audit opinion of our accounts if we didn’t.
Mr. Chairperson: Mr. Wishart, before I request you to hold on till–to discuss, hour being close to 8, what’s the will of the committee?
Mr. Cullen: Mr. Chair, if we could–I know there’s more questions here of the committee. If we could go till 8:30 and then review at that time, see how we’re making out in terms of questions. Hopefully the committee will give us at least another 30 minutes for questioning.
Mr. Chairperson: It has been suggested to 8:30. Is that agreed with the committee? [Agreed]
Mr. Wishart: Thank you for the fairly detailed answer. I knew there was a long discussion around the process here.
One of the things that will be difficult, if you do change your accounting standards this coming year, is there an intention to restate some of the previous years so that we can do a fair comparison? Because there is quite a change in the process. Is that part of the plan?
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Mr. Thomson: There’s a requirement to provide comparative information. So you’ll see our just-completed fiscal year that we will report in under Canadian GAAP. When we prepare our accounts, assuming that we continue on the path and prepare accounts for fiscal ’13 utilizing IFRS, we’ll be required to report comparative information on the same basis.
Mr. Wishart: I was hoping to tap into some of your experience in the gas industry.
Certainly we’re hearing a great deal about the surplus of natural gas created in the US by the change in technology down there. Based on your experience, do you believe that the price of natural gas, both here and in the US, will continue its downward trend for very long? We’re certainly seeing signs of the industry retooling, but that all takes time, as you appreciate. Do you see continued decline in the natural gas prices?
Mr. Thomson: No, I don’t. I think what we’re seeing in the spot market right now is, you know, historic–not historically low levels, but certainly in–since the California crisis in 2000 we’ve got the lowest spot commodity prices for natural gas right now. That’s a function of the supply-demand imbalance and storage levels which are well above normal this year.
The current market price for gas at Henry Hub in the US is well below the cost of production. No one’s going to take it out of the ground if they’re going to lose money on every unit, so I don’t see that. And if you look at the forward curve for natural gas, it’s in contango, which means it tilts upward as you move out, and there are seasonal variations in the forward curve that are built into the forward curve.
It is a lower–it’s at a lower level. The forward curve, going out five years, is at a lower level than it was a couple of years ago–materially lower. But I don’t anticipate that the current spot price that we’re enjoying will continue for beyond a normal cycle through the next year and once storage levels become in balance. We’ve seen a huge pullback in the rig count for drilling for natural gas. The fracking rigs are being moved into liquids production by industry because, you know, the differential between oil and other liquids and natural gas is–has–out of all historical context for the energy content. So I do see an uptick.
I wish I knew how much, because I could make a lot of money if I could predict it so accurately myself.
Mr. Wishart: And thank you for your answer.
My next question, it relates a little bit to some changes we’ve seen in policy in the province, and I suspect the minister may want to jump in on this one rather than yourself. We’ve seen a coal tax come into place in this province which was designed to encourage the use of additional biomass. Unfortunately, we don’t actually have biomass production in the province of the type that works in these types of furnaces.
So we’re seeing a lot of the people that might potentially be users take a look at this cheap natural gas and decide that that’s probably where they want to go. However, when they approach Manitoba Hydro to talk about natural gas hookups, the costs have been horrendous–to talk about running gas lines.
The minister considering–I know there’s incentives for creation of further biomass processing and incentives to convert to biomass, perhaps we could expand the incentives to hook up to natural gas lines. It does seem like somewhat of a conflict of interest to be on both sides of that equation as a government.
Mr. Chomiak: I thank the member for the question.
I think there’s been a number of projects that have been under way with MAFRI and the Department of Energy for several years with respect to biofuels, and there’s several projects that are advanced.
I think the government policy of moving towards both the coal tax and the non-utilization of coal for space heating and–is something that affects rural areas in particular, quite significantly in this province. And I think we’ve looked at and are looking at a number of options and alternatives in order to ease that particular conversion to rural Manitoba.
So I’d be quite willing to accept any advice from the member opposite with respect to ensuring that those areas of rural Manitoba, particularly a number of the colonies and other related areas, are able to not only receive confirmation that some of their conversions that have recently been made, for example, to certain products, can be utilized, but we can provide incentives into the future. So it’s a good suggestion and we’ll follow up on it.
Mr. Wishart: Thank the minister for the answer to the question. So you would consider some sort of incentive program related to natural gas hookup that might be revenue generated off the coal tax. As I pointed out, the processing of biomass into pellets which was suitable for a lot of the–to replace a lot of the coal. Being generous on when the processors might come online will not actually total 10 per cent of the demand. So we have quite a period of start-up here that we need to find some way to accommodate, and natural gas might well prove to be one of those, but the cost of hookup is a bit of a barrier, so we would be looking at perhaps developing some type of incentive program for hookups in natural gas.
Mr. Chomiak: I thank the member for the suggestion. I would just state in general that we are looking at alternatives, as the member speaks, to situations as the member described and others that we’ll–that we’re going to be dealing with in the short term. And we also recognize the timelines and the—so I’ll accept the member’s statements and indicate that there will be some further discussion in this regard, and we’ll have further information to the member and all members in this matter as we speak.
Hon. Jon Gerrard (River Heights): First of all, welcome, Mr. Thomson, and congratulations on your appointment, and I wish you all the best. And certainly you have in trust from the whole province a very important corporation and we look forward to a good performance.
Just–I have several questions. Let me start with–you showed a slide with the commercial monthly bill per 10,000 kilowatt hours and Manitoba comes out considerably better than most other provinces. The rates–can you just tell us a little bit about the rate structure for corporations? Does that depend on volume here or in other provinces, and whether that advantage is consistent on the size of the volume use by corporations?
Mr. Thomson: Was your question our internal rate structure as compared to other places, or across our rate structures?
Mr. Gerrard: I’m just trying to get an appreciation of–you present it as one value but, in fact, you’ve got, I believe, different values depending on the volume of hydroelectricity used, and give me a comparison in terms of, you know, users depending on the quantity of electricity used and how that compares province to province.
Mr. Thomson: I’ll give you a very high-level response and if I know that we have information in terms of comparisons, jurisdiction to jurisdiction. Generally speaking, the higher the quantity and the demand, it’s not unusual to have rate structures in place that–where there’s a demand charge for reserving, you know, the capacity for industrial users or large commercial service users. So the fee is–or the rates are structured–there’s several components to the structure of the rates which can include a demand charge and even a ratchet in–based on what the peak month requirement is depending on the overall consumption level.
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The two comparisons that we’ve provided here, a residential customer that heats with natural–with–sorry, with electricity, so they get into that 2,000 kilowatt hour, it’s fairly consistent across jurisdictions. Generally at that level what you see is there’s a fixed monthly charge that pays for some of the infrastructure to support the service, and that varies quite greatly from–or can vary greatly from jurisdiction to jurisdiction, you know, 3 or 4 dollars a month up to 12, 15 dollars a month. So if you’re a very low user, your effective rate is higher when you’re in a jurisdiction like BC, for instance. FortisBC had a basic monthly charge in the order of $14. So the–so it really depends what your overall volume is even within those–the low-use rates.
As you get into the higher end uses, the rate design is a factor of the system to serve the loads, so where you sit on the system and the overall levels. And that will depend–so you go through a fairly complex rate design evaluation that takes in to consideration the kind of–how the system itself is designed, and that can vary from province to province, jurisdiction to jurisdiction, that the two that–simple examples if you will–but that meet a lot of the load requirement on our system where for residential and small commercial ratepayers there’s some consistency across jurisdictions in this country. But it’s a factor we picked, we picked a level of consumption and how the basic charge components are across the jurisdictions that we showed for comparison and what the unit rate is.
And then in jurisdictions like BC where you’ve got a trailing block rate that’s higher to encourage, you know, the initial consumption is at around 6 cents, 6 and a half cents in BC, and then you’re paying 9 cents for any consumption above a certain level. That’s a rate design that was adopted there–that I’m familiar with because I just came from there–and, you know, other jurisdictions have similar structures in place so we picked, in the comparisons that we’ve presented, we just calculated and reflected what a customer would pay at that level across the various jurisdictions.
Mr. Gerrard: Second question, last time we had the committee hearing and Bob Brennan was here, I asked him for information on the cost per kilowatt hour of generating of the energy or the electricity that we generated from Wuskwatim, and Mr. Brennan promised to provide that to me. He was not–didn’t have it available and he has not provided it since.
So I’m asking you today: What is the cost of the electricity generated when Wuskwatim’s completed? What would–how many cents per kilowatt hour?
Mr. Thomson: I’m afraid I’m going have to undertake to get back to you as Mr. Brennan did, but I’ll endeavour to do so. I don’t have that information with me.
Mr. Gerrard: Appreciate that and look forward to hearing from you.
In the–third question deals with the US exports, and just a clarification on–under the Northern States Power, you’ve got, to begin with, reference to 375/325 megawatts, and I’m unclear whether, you know, why you’ve got both 375 and 325 megawatt numbers there.
Mr. Thomson: Yes, I believe that–winter, summer supply.
Mr. Gerrard: Just a question about the–we’ve now got two wind energy operations which are contributing to the grid. One of the things that was discussed at a previous meeting was the need to look at how you integrate wind energy into a grid where you’ve got hydroelectric power, and I just wondered if you had any comments on how that was working in being able to balance, you know, the on and off nature of wind energy production.
Mr. Thomson: My understanding is that, operationally, it’s been working fairly well. We have the ability to bring, given the overall amount of wind supply on the system, we’ve got the ability to bring generation up and back it off within the levels that we’re bringing in from the wind farms. So it has been–operationally, it hasn’t been a big issue. As the mix of wind gets bigger, and in some jurisdictions, I think, it’s more and more of an issue, but Hydro is fairly well placed for being able to balance that load.
Mr. Gerrard: Yes. What are your vision, moving forward in terms of whether you’re looking at more wind plant in Manitoba, and what sort of timeline if you are?
Mr. Thomson: I can’t speak to that this evening. I’m just–I’m not familiar enough with what stage of development that that might be in at this point. And what we’ve done internally–I just don’t have that information.
Mr. Gerrard: Now, the Bipole II is looked at as coming online in 2017, the Keeyask in 2019, and Conawapa in 2024. I mean, you want to bring the Bipole III on board as soon as possible for security reasons. But in terms of capacity reasons, at what point do you critically need it? Would you need it by the time Keeyask comes on board or would it be when Conawapa comes on board?
Mr. Thomson: No, it’s required for the new generation from Keeyask as well.
Mr. Gerrard: For Wuskwatim, now you’re–talked about it being complete and operational some time later this year. I presume that means that the full 200‑megawatt capacity would be coming online. Is that right?
Mr. Thomson: That’s correct. The first power mid-June for the first turbine and anticipated having it fully operationally by end of October, with all three.
Mr. Gerrard: Now for–you know, for any power generation, it’s going to depend in part on the availability of the water flow. What’s the prediction in terms of the Churchill diversion and the provision of water ship flow for Wuskwatim and whether that would be, at any point, a limiting factor or would it be a steady, constant 200 megawatts?
Mr. Thomson: Well, I think that it could be a limiting factor in a drought situation but we’d experience that across our system. And I’m not–again, I’m not familiar enough yet with–I know that we designed the system to provide firm capacity for–based on expected water flows. And I don’t want to misspeak on that so I might–it might be better if I confirm that to you, after the fact, for that question.
Mr. Gerrard: Interestingly, sometimes the, you know, drought, rainfall situation is quite different in the north than in the south, so, I mean, that may actually be buffering capacity. But, I mean, it would be very interesting to know whether–what the expectation is and what the prediction would be based on past flow rates. Yes.
Mr. Thomson: Well, I don’t have that information at my fingertips, but I think if you looked at the total production on the system by our total cost, that would be the easiest way to express that. I–and I can undertake to get that information for you.
Mr. McFadyen: Mr. Chairman, one of the good things about not facing an imminent election is that you have the ability to go back and clean up misstatements, and I want to just do that quickly on the issue of the cost estimates on Bipole III. There are–there’s dispute over the estimates and there have been a few different numbers put out. The minister has correctly indicated that the $3.2 billion number was raised in–either at or just ahead of our committee meeting in May of last year, and so that $3.2 billion number is on the record from a committee meeting from May.
I would ask you, though, to take a look at the–because there were three different numbers that were printed at three different times.
There’s a–there’s CEF 10 and the preceding CEFs which estimated it at around $2.2 billion inclusive of converters. That was revised; there was a review–there was some dispute as to what the number was, and it was revised in a review done by Hydro sometime in the spring of 2010 leading up to that committee meeting to $3.2 billion. But that was done in part because of a leaked document–an internal document which was made public around October of 2010. It was dated earlier than that, but it was made public around October 2010, which estimated the cost at $4.1 billion. So that explains the reference to $4.1 billion in the PUB order of January 17th. So that’s the order of 5/12.
So I think rather than ask you to comment on the difference between the 2.2 and the 3.2, I would just ask you to take a look at all of those relevant documents that have laid out different estimates for the project, and ask if you would just undertake to satisfy yourself as to which is the most accurate estimate of the cost going forward.
And the question is asked on the basis that, at this point, a project of this magnitude that really has barely begun, these are estimates. They’re forward looking. Nobody knows with absolute certainty what it’s going to be. But given the gap between the internal document which said 4.1 and the public document which said 3.2 prior to the last committee meeting, I think there are some significant issues to dig into, and that you’ve got an opportunity to dig into with senior staff in the corporation over the next period of time so that we don’t end up with surprises going down the road as the project gets under way.
But with that said, the minister was right; it did come up. The 3.2 number did come up just before the last meeting which I had–didn’t recall when I asked the question. So does that provide any clarity around what we’re getting at here?
Mr. Thomson: Yes, I believe so, and I could assure you that I stay up at nights thinking about these things, so.
Mr. Gerrard: I want–as you may know, I’ve been a pretty strong advocate of exploring using lines under water–under Lake Winnipeg, for example, and, I mean, there is a report already which suggests that there is potential feasibility for using a line under Lake Winnipeg for Bipole IV.
And I just–since you’re starting, that one of the things that it would seem to me that’s quite important is to keep an eye on what’s happening with the underwater technology and the advances because it’s an area which may become useful for Hydro in the future.
Mr. Thomson: In fact, I am aware of some of the work that’s been going on and some of the research, and I’ve got a stack of reading and some–and there is a document in there that’s starting to get closer to the top, so. But, no, I am quite interested in looking at the thing–technology advancement as we move forward.
Mr. Helwer: The minister had indicated that the Bipole III is not going to run through Riding Mountain, but it is going to run through the Riding Mountain biosphere, and there is a group of municipal, federal, provincial, and as well as First Nations that belong to an organization that administers that area. And I don’t believe this has ever come up in front of them yet, so it’s something that they do need to deal with.
Further question to Mr. Thomson, I’d asked about the community development fund and the initiative, and we–apparently we have a report that says we have 27 communities. In here you’d mentioned 60 or so that have been offered. Can we get the names of those 60 and what they have been offered?
Mr. Thomson: I don’t believe that they’ve been offered funds at this–the communities have been directly offered funds. I think there’s–we’ve estimated that there’s 60 communities that may be eligible for–to participate in, but I will look. You know, if there have been, and I’m unaware of that at this point, then we can look at what’s there.
Mr. Helwer: Mr. Brennan has retired after a long and successful service, and when we get a new CEO or other executive coming in, there’s often a turnover in senior executive ranks. Have we seen that happen in Hydro or has it been pretty static?
Mr. Thomson: Not as of yet, and I hope not any time soon. We’ve–what we–you know, what–one of the–one of my challenges moving forward will be dealing with succession planning. I’ve got the benefit of a seasoned, well-experienced team, but, you know, I do–I just signed a letter to one of my team recognizing his 45 years with Manitoba Hydro, and, you know, I’ve got a relatively small executive team, half of which would meet the new Old Age Security guidelines. So it’s present in my thinking and–but I also–you know, the team’s on board and I believe that they’re interested in working with me. I’m certainly getting support from them and I’m very appreciative of their level of commitment and dedication to the company, and, again, the support they’ve lent me because this is a pretty steep learning curve for me. But as time unfolds, yes, we’re going to see some new people coming into the executive team. It’s inevitable. But I’m not experiencing a wholesale revolt, thankfully, and I hope to continue with that.
Mr. Helwer: Thank you, to you, through you to Mr. Thomson. You have some negotiations going on now with the IBEW I understand, and they have–you have about, oh, another three quarters to finish those, and do you see–foresee that negotiation having an impact on rates going down the road?
Mr. Chomiak: There’s a general rule that I’ve had, as minister responsible for any entity, of not to discussing publicly negotiations or the state of negotiations, and I don’t think we can and should discuss these kind of matters in the public sphere because it’s not generally in the public interest when you’re in negotiations. So that’s a long way of saying I don’t think that question can be answered in this context insofar as we’re in collective bargaining agreements, and it’s served me well through my years both in opposition, where I was chastised for asking questions in that regard and stopped, and as government. It’s been a good policy not to deal with those issues publicly.
Mr. Helwer: Well, I guess the next one’s probably going to be sensitive too then. There’s always lots of questions about Mr. Brennan’s pay and whether it was high or whether it was low and some people estimated he was underpaid, but obviously this is a question about what Mr. Thomson’s settled on for a contract and is that open for disclosure?
* (20:30)
Mr. Chairperson: Well, let me ask the committee. The time being close to 8:30, we’d like to know the will of the committee.
Mr. Cullen: With the committee’s indulgence, I think the critic just has a few more questions, so I don’t think it will take too long for us to wrap up if–with the committee’s indulgence on that.
Mr. Chairperson: Is that agreed? [Agreed]
Mr. Chomiak: Yes, we will continue to–the practice that we have in the past with regard to that.
Mr. Chairperson: Thank you.
Mr. Helwer: And that would be what?
Mr. Chomiak: I think, generally, the pay scales and benefits payable to senior management across corporations, both in the–in the public sector has generally been disclosed to Manitoba.
Mr. Helwer: I understand Manitoba Hydro International is working in the Nigerian area, and they have recently been awarded a contract for some $24 million to work with the Nigerian government on privatizing their hydro in that area. Can you comment on that, and if that’s something that you see as an important part of Hydro’s mandate?
Mr. Chomiak: Manitoba Hydro International is a very important component, and is recognized worldwide, in fact, for some of the activities that they undertake and has been encouraged in its roles and as a consultive capacity providing service around the world, and will continue to do so. And it’s–the experience, for example, in the direct, current field and the utilization of HVDC transformation has been world setting in–from Manitoba, and has been utilized around the world in terms of transmission. And Manitoba Hydro International will continue to work around the world, as they have in the past, on projects, many in Third World countries.
Mr. Helwer: Well, I understand that this particular project is to prepare the company for privatization, and is that a project that this government supports and is that the plan that you have for Manitoba Hydro down the road?
Mr. Chomiak: I guess the best way I could answer this, Mr. Chairperson, is to say, no. And I’ll leave it at that, insofar as I know there’s time considerations.
Mr. Helwer: Well, I think we–I just have a couple more questions that I think we’ve asked of past board chairs. So seeing as we have a new one, perhaps we should ask the current chair, Mr. Fraser, through you, Mr. Chair, how often do the board chair and CEO meet with the minister? Is a regular scheduled meeting?
Mr. Fraser: Well, again, Scott and I have only been involved for a relatively short period of time, but I would anticipate that we would probably meet once a week or every two weeks, something like that, depending on the issues and what’s going on. It may vary in terms of more frequently at certain times and less frequently, depending on the issues at Hydro, and so on. There isn’t an ongoing schedule that I’m aware of, but–I mean, that’s my understanding would basically be a weekly meeting.
Mr. Helwer: Through you to Mr. Fraser, Mr. Chair. You’ve operated in a number of board environments and seen several boards operate. Do you get a lot of guidance from the minister, from other elected officials in this regard, and is it more so than in other boards that you’ve participated in?
Mr. Fraser: Well, again, I mean, in–the minister and I have probably met three or four times in, you know, the short period that I’ve been there, and they’ve basically been a sharing of information. So there–but there hasn’t been specific direction on any issues.
I mean, the hydro planning cycle is a very long planning cycle, as we see in terms of the construction projects and the capital projects. I mean, it’s generally a 10-year rolling plan, and in some cases, the–there’s been a need for providing a 20-year rolling plan. So it’s not something where there’s dramatic changes in a short period of time. I mean, these things–projects take literally eight, nine, 10 years in a lot of cases, from planning and the various licensing and approval and being able to get access to locations and that kind of thing. So, I mean, the framework is pretty well established in what they refer to as the IFF, which is continually updated.
And as Mr. McFadyen has indicated on a number of occasions today, I mean, based on the best estimates available at any given time which continually change as a result of change assumptions, interest rates, foreign exchange rates, construction costs, commodity costs, various things. So, I mean, it is a very fluid thing that needs to be monitored on an ongoing basis, because it is very dynamic.
Mr. Helwer: Through you, Mr. Chair, to Mr. Fraser. You have a number of new board members that are new to the Hydro board. They may have served in other board capacities elsewhere, but do you have particular training for new board members?
Mr. Fraser: There is orientation package, and we are in the throes of convening orientation for the board. There’s also a number of seminars, courses, that are put on by the Crown Corporations Council. And I got a letter from them just a few days ago on–kind of the next round of courses that are coming up, and which would be distributed to all board members, not just new board members, in terms of various issues that board members should be up to date on.
Mr. Helwer: I guess from other Crown committees, we’ve heard about their boards and how they’re treated, and I’m just curious on this particular one, is there a stipend for being a board member, a vice-chair and a chair, and what might those amounts be?
Mr. Fraser: I can only speak from my personal experience.
I’ve been on the board for, I guess, approximately six years and the stipend has been, I believe, $7,200 a year; it’s like $600 a month. I believe all board members get that. I haven’t been aware of–I think at one point in time there was vice-chair. For recent time, I don’t think anybody has been vice-chair. And the chairperson normally has a contract, which I don’t have yet, and I haven’t been paid yet. But I’m sure that you’ll get around to that. So I’m not sure what I’m making, to be honest.
Mr. Helwer: For those new board members and for all board members, are there certain qualifications or credentials that you look for in order for appointing someone to the board?
Mr. Chomiak: Yes, I don’t–it’s probably more appropriate that I answer that question, as generally the minister responsible is ultimately–signs off on board appointments after reviewing through their committee and through Cabinet, and there’s a variety of factors depending on the type of board. And clearly we want to have–and we’ve had very good success, particularly with the Hydro board, of the kind of responsibilities they have.
One of the issues that we’re very proud of with respect to this particular board is the fact that people of First Nation-Aboriginal background are four members on a board of 11, which I think is a first time in Manitoba. And it reflects the importance of First Nations to the development of Hydro and to the future of Manitoba.
So, for example, Chief Crate, who’s on the board, has been chairperson of one of the committees of the AMC for a number of years in dealing with complex financial matters, and is now on the board of Hydro. That’s an example of not only diversity but also an example of strength and of the variant type of personalities on the board.
Clearly a financial background, public service; all of those issues are looked at with respect to balancing boards and ensuring that there’s a fair representation of Manitobans on the board. So, in general, that’s the process for board selection and board governance in Manitoba.
* (20:40)
Mr. Helwer: Are the board meetings open to the public and are the minutes of those board meetings available to the public?
Mr. Fraser: The board meetings themselves are not open to the public.
With regard to the minutes, I must admit I’m not sure. I mean, I presume that there are policies in government with regard to those things that I would presume that Hydro is following whatever those policies are. But I know certainly the provincial auditor attends all of the board meetings, all of the audit committee and finance committee meetings and has access to all that information, and certainly the external auditors who are Ernst & Young have access to all that. Whether the general public does and what the provisions are under the freedom for information legislation with regard to those specific things, I must admit I’m not aware of them.
Mr. Helwer: Just one more question, I think, probably, through you to Mr. Thomson, didn’t want him to feel bored here at the end, but in your presentation you were talking about Keeyask, and the statement was if we build Keeyask. So is it under debate whether that particular structure will be built?
Mr. Thomson: No, not internally. I mean, we’ve got to go through a review process and get it certificated to build, possibly a poor choice of words on my part, but our expectation is that we will build it and we’re going to pursue that project. As I’d mentioned, we have a need for new generation by 2020-2021, and the plan is to get that built a year in advance of when we–in and around the time that we need it. So that’s the course that we’re on.
Mr. Helwer: Well, Mr. Chair, I think we’ve exhausted our questions for the evening, and we do have a suggestion of whether we should pass a report and the suggestion, I guess, we could make is that we pass the report for the year ending March 34th–31st, 2008.
Mr. Chairperson: Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31st, 2008–pass.
Shall the Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31st, 2009 pass?
Some Honourable Members: Pass.
Some Honourable Members: No.
Mr. Chairperson: The report is accordingly passed. No? The report is not passed.
Shall the Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31st, 2010 pass?
Some Honourable Members: Pass.
Some Honourable Members: No.
Mr. Chairperson: The report is not passed.
Shall the Annual Report of the Manitoba Hydro-Electric Board for the fiscal year ending March 31st, 2011 pass?
Some Honourable Members: Pass.
Some Honourable Members: No.
Mr. Chairperson: The report is not passed.
The reports which are not passed, kindly leave them on the table here.
The hour being 8:42, what is the will of the committee?
Some Honourable Members: Committee rise.
Mr. Chairperson: Committee rise. Thank you.
COMMITTEE ROSE AT: 8:43 p.m.