Proceedings of the Standing Senate Committee on
Energy, the Environment and Natural Resources
Issue 12 - Evidence - May 27, 2014
OTTAWA, Tuesday, May 27, 2014
The Standing Senate Committee on Energy, the Environment and Natural Resources met this day at 5:58 p.m. to study non-renewable and renewable energy development including energy storage, distribution, transmission, consumption and other emerging technologies in Canada's three northern territories.
Senator Richard Neufeld (Chair) in the chair.
[English]
The Chair: Welcome to this meeting of the Standing Senate Committee on Energy, the Environment and Natural Resources. My name is Richard Neufeld. I represent the province of British Columbia and I am chair of this committee.
I would like to welcome honourable senators, any members of the public with us in the room and viewers across the country who are watching on television. As a reminder to those watching, these committee hearings are open to the public and also available via webcast on the sen.parl.gc.ca website. You may also find more information on the schedule of witnesses on the website under "Senate Committees."
I would now ask senators to introduce themselves, and I will start by introducing the deputy chair from Alberta, Senator Grant Mitchell.
Senator Boisvenu: I'm Senator Boisvenu from Quebec.
Senator Massicotte: Paul Massicotte from Quebec.
Senator Sibbeston: Nick Sibbeston from the Northwest Territories.
[Translation]
Senator Ringuette: Pierrette Ringuette from New Brunswick.
[English]
The Chair: I would also like to introduce our staff, beginning with the clerk, Lynn Gordon, and our two Library of Parliament analysts, Sam Banks and Marc LeBlanc.
On March 4, 2014, the Senate authorized our committee to undertake a study on non-renewable and renewable energy development including energy storage, distribution, transmission, consumption and other emerging technologies in Canada's three northern territories.
Today marks our fifth meeting on this study, and I'm pleased to welcome the following witnesses: from the Canadian Electricity Association, Mr. Jim Burpee, President and CEO; and from ATCO Power, Doug Tenney, Vice President, Aboriginal and Government Relations. Thank you very much for being with us today. Again, I apologize that we're a little bit late, but the Senate lasted a little longer this afternoon in discussions and we can't start until they're finished.
Mr. Burpee, we look forward to your presentation.
Jim R. Burpee, President and CEO, Canadian Electricity Association: Thank you, Mr. Chairman and honourable senators, for inviting us here to discuss energy and resource development in Canada's North.
Our remarks will focus on the integral role of electricity as a critical enabler of development and will outline the related challenges and opportunities, not only for the North but the rest of Canada.
Every day, members of the Canadian Electricity Association, or CEA, produce, transport and distribute electricity to industrial, commercial, residential and institutional clients throughout Canada. The energy we produce, transport and sell is essential for our activities at home, at work and for the entire economy.
I want to mention, for the purposes of your study, that the Northwest Territories Power Corporation and Yukon Energy are active members of our association. I understand you met with both during your recent trip to the North. I'll also add that I'm very optimistic about discussions we're having with Qulliq Energy Corporation around joining CEA, so stay tuned on that one.
When discussing access to electricity in the North, it is important to consider electricity systems and, perhaps most importantly, the plans of electric utilities and governments in provinces that share borders with the territories.
The reality is Canada's North is isolated from the North American high-voltage grid. While this is not unusual in light of the development over time of electricity grids from urban centres out, it does highlight key challenges, geography and the proximity of the territories to existing and new generation and transmission infrastructure and low population density.
To increase grid access and to power major resource development projects in the North, new and expanded electricity infrastructure will be required. In some cases this may include expanding the North American grid to include some portion of the territories. That is why it's important that electric utilities and Aboriginal communities, through leadership by provincial, territorial and federal governments, take a collaborative approach to developing reliable and sustainable electricity infrastructure in the North.
Currently, electricity utilities in the territories are willing to take on this job, but challenges remain. Capital needs to be put in place before these projects can move forward.
CEA believes that the federal government should consider financial instruments, such as loan guarantees, to alleviate upfront project costs and continue to support emerging technologies such as those being supported and funded through Sustainable Development Technology Canada. These projects are reflected in the recommendation in our newest policy paper, Vision 2050: The Future of Canada's Electricity, which you have received copies of.
For much of the Far North, grid integration is not a viable option. Our members are developing innovative solutions to address the challenge of reducing reliance on diesel generation in remote communities.
For example, BC Hydro has a remote community electrification program which pairs diesel generation with other sources including battery storage, smart meters, remote monitoring and upgraded wiring, and Nalcor Energy is working on an innovative project in the remote island community of Ramea. The Ramea wind-hydrogen-diesel project converts excess wind power into hydrogen, which can be stored and then used to produce electricity when the wind isn't blowing. The project has great potential for offsetting diesel use in remote communities and is about to enter a second phase in which they hope to address ongoing challenges with the hydrogen generator technology.
These are steps in the right direction, but there needs to be a collaborative approach to stakeholder engagement through a shared vision: one led by federal and territorial governments which factor in support for new and emerging technologies as well as larger infrastructure projects.
To speak about the scope of some of these challenges and some innovative projects that are currently being considered in Alberta, I'm pleased to be joined today by Doug Tenney, Vice President, Aboriginal and Government Relations from ATCO Power, another one of our member companies.
Doug Tenney, Vice President, Aboriginal and Government Relations, ATCO Power: Good evening, everybody. As you are well aware, the North is blessed with significant energy resources, including a vast amount of hydroelectric generation potential. Although there is some hydroelectric generation installed in the North, not all communities are served by hydro: many still rely on diesel. I think Jim has mentioned a few of those already.
The load in a lot of those communities is very small and they're located great distances away from the hydro sources. Load growth and diesel price increases may change the economic viability of hydro.
ATCO is an active participant in the North through our ownership of Yukon Electrical Company, Northlands Utilities (NWT) Limited, Northlands Utilities (Yellowknife) Limited, and we've got a small team chasing hydro generation opportunities to displace diesel in some of those communities, together with their Aboriginal partners.
Today, however, I want to focus on the potential for northern development for export into Southern Canada.
I think you have a number of graphs in front of you. I'll start speaking about the first one. The first one is prepared by the Alberta Electric System Operator, and you can see from that that Alberta's load resource balance, load and supply presents an attractive opportunity for hydro development in the North. The very top dashed line represents the load forecast in Alberta. It's growing at somewhere between 2.4 to 2.6 per year from now until 2032.
Just above that is the line you would need for an effective installed capacity. That represents 15 per cent above load, which is called a reserve margin, and that is to account for when you have generation units out of service, whether planned or unplanned. That's the line you will need to serve.
Down below in the shaded area is our generation installed capacity. You can see it's declining quite rapidly, and that's largely due to the coal retirements due to recent federal regulations.
Overall what that leads to is about 5,700 megawatts of new capacity needed by 2022, and 11,000 megawatts needed by 2032. That represents about a doubling of Alberta's installed capacities.
Turning to the next graph, they're a bit out of order and I apologize for that. If you could look at graph number 4, that's a comparison of the alternatives.
While ATCO believes we're bound to have all kinds of renewable generation in play, be it wind, small run-of-river hydro or solar, and we think what we really need to focus on to replace our coal that's retiring is base-load generation.
There are really four alternatives you can consider for base load: coal, nuclear, natural gas and large-scale hydro. As I've mentioned, the federal government regulations suggest that any new coal that gets built has to have the same GHG, greenhouse gas emissions, as combined-cycle gas turbines. That's going to be difficult unless you have carbon sequestration in storage. You can see by the graph on the line that says "clean coal," that's what that would look like. It looks cost prohibitive.
Nuclear for sure is an option, although it looks challenging economically as well as it may have some long-term environmental implications. That leaves you with natural gas and hydro.
Natural gas is a feasible solution; however in Alberta if that's all we rely on we're going to subject customers to the risk of increases in gas prices and increases in a potential carbon tax.
On that graph there are a lot of numbers there, and I'm not going to get into all the details on it. What's important to recognize is that we're trying to guess what prices are going to be in the future, not necessarily what prices are today. You can see when we identified the CCGT, or combined-cycle gas turbines, we've shown different fuel prices: $3 gas, $5 gas and $7 gas. It's hard to predict what that gas price is going to be into the future.
As well, we've shown what impact a carbon tax would have. You can see, from looking at those, that the hydro bar, the second, is competitive under a number of reasonable gas price and carbon pricing scenarios.
I should also mention that this only looks at hydroelectricity. It doesn't take into consideration some other benefits you would get from having a hydro plant, which would be water storage. We have a project on the Athabasca River that, if you took into account the economic value of stored water for the oil sands industry and the flood mitigation protection it affords the city of Fort McMurray, those numbers would probably get closer to the 65 to $70 range.
Turning to slide number 2, the second in your package, it illustrates that about 75 per cent of the hydro potential in Alberta is located in three river valleys: the Peace, the Athabasca and the Slave. ATCO has studied all three of those and has centred on three projects: two of them on the Athabasca River and one on the Slave River. You can see also that the Government of the Northwest Territories has identified about 11,000 megawatts of untapped hydro potential in the N.W.T., and some of those are listed on there.
Turning to slide number 3, as can be seen here the majority of generation sources in Alberta are developed near the natural resource. Coal is built at the coal mine. That's because of the high cost of transporting coal. Wind and hydro plants are developed where the resource is the strongest, and co-generation exists at sites such as the oil sands and in the industrial "heartland," the Fort Saskatchewan region of Alberta.
As such, it's important to create and maintain a strong transmission network that enables these generation sources to be utilized. The Government of Alberta has recognized that by their recent expansion of the transmission system in Alberta and the high voltage transmission lines they've built on the east side of the province between Edmonton down to Brooks, as well as Edmonton to Calgary. They've also recognized they need to build transmission to renewable and alternative energy zones, and they've indicated that the northeast part of the province is just that. This would help unlock the green energy corridor. The first hydro project built up there would then have transmission built, which would enable the transmission to be far cheaper for the subsequent projects to happen.
When developing a hydro generation project, the economic, socio-economic and environmental impacts must be carefully considered. Finding the right balance ensures that the best project is selected, permitted and built. It's ATCO's belief that any successful energy development in the North requires real engagement with Aboriginal groups. This includes full participation in the regulatory and permitting process, meaningful consultation, training and jobs, contracting opportunities, and equity participation in the projects.
Government, too, needs to play a large role in providing tangible support. This can take the form of continued support; of more streamlined, harmonized, regulatory processes with mandated timelines; helping to establish commercial frameworks that allow for recognition of the significant expenditures that are required in the development of hydro before you know if you will get a permit; as well as recognizing that there are other economic and socio-economic benefits to hydro above power generation that should allow for joint funding for those studies; as well as these projects take over 10 years, probably 12 to 15 years to develop. There needs to be a commercial framework established to create some revenue certainty for these projects. There's also a need for a policy structure to be in place to properly recognize greenhouse gas emission for e-power generation from large-scale hydro generation with storage capabilities.
The governments will need to help on Aboriginal support, including fulfilling their duty to consult, their resolution of any unextinguished treaty rights and long-term access to lands if required. Also, governments can play a role by including the bilateral transboundary water agreements between Alberta, the Northwest Territories, B.C. and Saskatchewan. That concludes my comments.
Mr. Burpee: If I can just wrap up, we recognize that the challenges here are not insignificant and there are no easy answers. In the case of what Doug has talked about, the Northwest Territories has a corridor of a lot of energy available, far more than what it as a territory can ever use itself. It needs to work in collaboration with Alberta or Saskatchewan in their plan with the support of the federal government.
Then you have a number of isolated communities that electrically will always be isolated. There we are looking at emerging technology. We are looking to get off diesel. Keep in mind that when diesel was put in it was the best technology at the time and had the advantage of relatively low capital cost and the fuel is relatively easily transportable and has good energy density. Now we're trying to move off that because it has become very expensive, let alone the environmental impacts of it. There's not a simple answer and it's going to require a degree of vision and governments working together with industry and Aboriginal groups, as Doug said, to make a difference. Thank you.
The Chair: Thank you. We'll start with the deputy chair, Senator Mitchell.
Senator Mitchell: Thanks, gentlemen. These are very interesting presentations. We really appreciate you being here.
I think we all are, but I'm very concerned about climate change, and I've talked a lot about a carbon tax. I've noticed, Mr. Tenney, on your chart that you are factoring in the possibility of carbon pricing in some of your estimates. Is your company getting to the point — I'm looking at chart 4 — where you are actually planning with a view to a carbon price in mind?
Mr. Tenney: Yes. In fact, in Alberta there is already a carbon tax in place, so it's already a reality. As well as with the federal government's coal regulations, ATCO is one of the entities that owns a significant amount of coal, so it is coming to its end, so we're planning for how we replace that coal fleet.
Senator Mitchell: On your chart you have $15 but you go all the up to $100 possible. Is your company actually advocating for a carbon price? Would it be your policy that we should have one?
Mr. Tenney: We, in fact, do have one right now in Alberta, so it looks like it's a reality.
Senator Mitchell: A bigger one? A real one? I don't want to put you on the spot here.
Mr. Burpee: Can I help him out here?
Senator Mitchell: Anybody can jump in.
Mr. Burpee: In Vision 2050, we talk about mechanisms for pricing carbon or for dealing with reducing emissions and look at and compare the pluses and minuses of feed-in tariffs, tax policy and other things. The conclusion we came to, if we want to deal with greenhouse gases in the most cost-effective way, you have to price it in the economy, minimum North American-wide. A province on its own can only do so much. A country on its own can only do so much because you get significant carbon leakage, especially in electricity where you have other options that are more carbon-intensive, especially south of the border. From an electricity perspective, we are saying, if we're going to do it, economy-wide, North American-wide, let the markets work, and that will certainly help the economic case for other technologies to develop, too. That's the other reason for doing these what-if scenarios. How does it compare? What is the value and the crossover at that point?
Senator Mitchell: Thank you. Mr. Tenney, I appreciate your map of the possibilities. Are you suggesting — maybe both of you can answer this — that a project in Alberta would feed electricity into the Northwest Territories? Or is this map configuration inferring the opposite, that projects in the Northwest Territories could feed south? You have the Slave River here, the Athabasca and the Peace. What stage of consideration of which way that might go or is it real at all?
Mr. Tenney: I think it's helpful to understand a bit about what the Northwest Territories electrical systems looks like. They have the Taltson grid. The Taltson is right now an 18-megawatt project that is immediately north of Fort Smith. It's about 50 kilometres north. It's currently serving Hay River, Fort Smith and Fort Providence, that hydroelectricity energy, and it's spilling water; it has surplus capacity on that. In that immediate area, they don't really need any hydro or electricity to flow north. What we were talking about is the real potential to develop some of these big projects and sell the kilowatt hours back into the Alberta market. But once the project is built, clearly it's built and you could serve areas in the north as well.
Senator Mitchell: Because their answers have been so efficient, my question has been so efficient. Can I have one more question?
The Chair: One quick one, yes.
Senator Mitchell: Thanks, chair — not to take advantage of you. Could you give us a rough idea of where electricity storage technology is, beyond holding water? Is that advancing quickly? Are we making real progress where you could actually store wind-generated or solar-generated power?
Mr. Burpee: The general options are a variety of different battery technologies; there is not just one; there are several. There's the ability to create hydrogen and use either fuel cell, typically, to convert it back into electricity, and there are things like flywheels. Depending on where you are in the system and what you need, some technologies are better than others. In Ontario where you have wind farms that might be at the end of a long distribution line, the storage provided by a flywheel gives attributes to the other system that are better.
The issue for all of them, any time you convert electricity to another energy form to bring it back to electricity, there's an efficiency loss. The other way to think of storage is what end use energy service you want. If it's heat, which is what they're looking at in PowerShift Atlantic with New Brunswick Power and some of the Maritime provinces, where they get variable load and use hot water heaters or thermal storage heaters for home heating, and when the wind blows they heat up and can draw heat out when you don't, and to the homeowner, they don't notice any difference. You don't have to convert it back into electricity. There are storage options that are looking at managing load in a variable manner. Traditionally, generation always had to follow load. Now we're getting to a point where load can follow generation to avoid the storage of flipping back and forth.
The Chair: Maybe if I could ask a question in relation to that. When we were in the Northwest Territories and we had a presentation, they never spoke about tying into Alberta. They talked about tying into Saskatchewan, Uranium City and beefing up those dams around the Talston. I think there was another name because they want more electricity to go through the same way to Yellowknife and up towards Snap Lake to some large mines there. It's the same company, but you come from Alberta with a different approach. Are those both options that you're looking at? It's strange we didn't hear that. I asked the question and they said that no, Uranium City would be the most logical place for us to tie into the grid. They would have excess electricity and would sell it back to the grid instead of being locked in and isolated. Can you explain?
Mr. Tenney: I should be clear that we own two companies in Northwest Territories Yellowknife and Northwest Territories N.W.T. I suspect you met with the Northwest Territories Energy Corporation, the Crown utility that wanted to develop the Taltson hydro project. I suspect that if I were in their shoes, I might be looking to tie into Saskatchewan as well because you can sell to SaskPower with a long-term contract, whereas in Alberta it's a deregulated marketplace. You have to market to individual customers that likely aren't as bankable as a Crown corporation or SaskPower. The certainty of a long-term contract is what they're after.
The Chair: That's true. We met with the Northwest Territories Energy Corporation; so your observation is correct. That is another option. Another reason they might look at that option is that they will have the same numbers as you have. The Slave and the Athabasca are 3,300 megawatts. Looking at the first graph, you're going to need an awful lot more than 3,300 megawatts in Alberta to make up what you lose in coal. I don't want to talk about Alberta too much because we're focusing on the territories. However, that in fact is true, is it not?
Mr. Tenney: Yes. Our shortfall, I think I mentioned, of 11,000 megawatts by 2032 will need to be made up by more than just the resources if we're looking for all hydroelectric generation. It will have to come from more than just Alberta. Clearly other forms of generation will supply some of that load — combined cycle gas projects, co-generation projects. There will be a number of them.
Senator Ringuette: What you present to us is very interesting.
What stage of development are you at with your business plan? You have provided us with a potential number of megawatts and a potential distribution network. Where are you at with your business plan to move it forward?
Mr. Tenney: I would say that on all the projects, the two on the Athabasca and the two on the Slave, we're at the front end. The Slave project we started studying together with our partner back in 2006 or 2007. I mentioned that ATCO and our partner are adamant about how we work and engage with Aboriginal communities. The project on the Slave would inundate a small portion of Smith's Landing First Nations reserve land. We had worked with them for probably a year and a half to conclude what we called the feasibility and cooperation agreement. We didn't quite get it executed. There was a band council change and the new chief and council decided they didn't want to study hydro. That project has been on hold since then. Subsequently, we looked at our two sites on the Athabasca, and we're in the early stages of those projects. We haven't begun to engage with Aboriginal communities yet; so we're at the front end.
Senator Ringuette: Yes, there's a long way to go. You mentioned 12 to 15 years for not only the construction but also the preparation, environmental assessments and so forth.
Mr. Tenney: That's correct. We think that if things go amazingly well — but unfortunately they never do — it would probably take five to six years for the environmental process to find out if you can get a permit and probably another five to six years of construction after that. Our problem is that you can see the big wedge of need. If we don't start on hydro, it unfortunately always stays 12 to 15 years away.
Senator Ringuette: Exactly. It's a long-term project construction-wise with all the capital requirements. To have access to a first draw of capital to move forward, you need to have quite a business plan developed to sell shares. Is your plan to get a loan or to sell shares? A move forward needs to happen.
Mr. Tenney: Right. When I talk about the Slave project, it's always ATCO and our partner TransCanada. We did spend a lot of our own money to do the preliminary work of early stages concept, schematic layout of what a generation project would look like and the economics. We have spent a fair amount of money. On the Athabasca, we've done a similar amount of work. It's small in comparison. The Athabasca will get into the $5 billion to $6 billion range and the Slave will be $7 billion to $8 billion range. We haven't spent a lot in comparison to that.
To get to the point of submitting an environmental impact assessment, we'd probably need to spend in the neighbourhood of $30 million to $40 million for the proper Aboriginal engagement and to do those studies. We would look at having some kind of funding arrangement with various levels of government.
Senator Ringuette: I'm trying to compare what you're looking for and how Newfoundland approached it for their development at Muskrat Falls to get to the stage they are at now with the feasibility study done and so forth. It was only when they reached the current stage that they got a loan guarantee from the federal government.
Mr. Tenney: Correct.
Senator Ringuette: I suspect that any kind of major project like that to serve all these communities and have decent revenue and secure supply of energy would be looked upon favourably.
Mr. Tenney: Jim will maybe jump in and help me but I think the difference is that Nalcor is a regulated utility that has an obligation to serve customers. They would have spent the money knowing they had a backstop in that ratepayers would fund those costs. In Alberta with our deregulated market, there's no backstop for any money that's spent. Large-scale hydro throughout Canada has been developed only by Crown corporations. They did have, if you would, a funding arrangement with the provincial government. I think ATCO would need to look at a similar model.
Mr. Burpee: Worldwide, large-scale hydro has always been government just because of the inherent risk. How far do you go down before you actually know? Who has a balance sheet big enough to handle the write off and reallocate the cost, whether to the taxpayers or ratepayers, who are often the same people? Large-scale hydro in the past has taken large government involvement.
Senator Black: Let me say as a senator from Alberta that my colleagues should know that ATCO is one of the great companies in Alberta. I'm very appreciative that you're here and appreciative of the work you do.
I would like to understand, in terms of the developments you're proposing, your comments that relate principally to an export market from the territories.
Mr. Tenney: Yes, that's correct.
Senator Black: I wanted to understand that. The export market could likely be Alberta or wherever.
Can we talk about the internal market, please? You pointed out, Mr. Burpee, the need for commercial realities, Aboriginal engagement, government support and an ordered regulatory framework — the four hurdles that you accurately identified. Is there any realistic opportunity for electricity development in the North for the internal market?
Mr. Burpee: For the Alberta internal —
Senator Black: The internal market — the market in the Northwest Territories or Nunavut.
Mr. Burpee: The challenge with the Northwest Territories is they don't have the scales of need. When you're developing hydroelectric, the scale which you build is the function of what available water is available, the fluctuation during the year, the flooding impact if you're building a dam; but they tend to be large capital projects which get very expensive very quickly, and if you have a small number of customers as an off-take. What we haven't gone into yet is the role of building that infrastructure, including transmission, to support other resource development; so whether it's a mine, and then who is paying for what? What's the allocation of costs between the new customer and an existing customer? You run into a bunch of those issues. There are lots of different ways to do it, but they all end up in a political process and decision of some kind.
Senator Black: I would agree 100 per cent. These are the economic facts.
Mr. Burpee: Yes.
Senator Black: I understand that 95 per cent of the power consumed in the Yukon is based on electricity.
Mr. Tenney: You mean hydroelectricity?
Senator Black: We should be clear on that. I understood hydroelectricity.
Mr. Tenney: I'm a bit dated. I worked up there at Yukon Electrical, but it was a few years back. I would think your number is pretty close.
Senator Black: Is the source of the energy BC Hydro in the Yukon?
Mr. Tenney: No, it's not the source. They have a hydroelectric facility right at Whitehorse, and they have another at Aishihik. Aishihik is the name of the hydro; so it's a few hundred kilometres north of Whitehorse. It is tied together in the Yukon grid.
Senator Black: Is there a simple answer as to why what has happened in the Yukon can't be mirrored in the Northwest Territories? Is there a simple difference?
Mr. Burpee: The projects that Doug talked to before, the hydroelectric, the two he mentioned, and it's the same idea. In some of these original grids that were developed, the development costs and a lot of the underwriting that were originally from mining operations had the need for the power and could afford it at that point.
The equation for a lot of mining companies today — without speaking for the mining people, obviously — is the economics of the miner are different. What's the longevity of a mine? If it averages 13 to 15 years, and you're building a hydro system and transmission to support that operation you're building an asset that is probably good for 50 to 100 years. Your mine life is not long. Can you afford what for them would look like an overbuild?
Their fallback position has been diesel because it's a cheaper capital cost and higher operating cost for the period. When the mine life is over, we just pack up and go and don't have the existing asset, which it has benefit for, to some degree, both the Northwest Territories and the Yukon there.
Now they're faced with the issue, they have the opportunity for mine expansion. What's the appropriate capital contribution from the new mine? And, again, it's a cost allocation process. So there are some opportunities.
The Chair: One thing we learned on our tour was the number used was correct, Senator Black, 95 per cent of the electricity in the Yukon is hydro, but they need more. They're having difficulty, exactly the same as ATCO is, but in the Northwest Territories it's 40 per cent hydro. The other problem is the communities are so far flung and so small that you just don't run a hydro line to all of them.
Senator Massicotte: Thank you for being with us.
On this chart, page 4, just to make sure I understand it right. Using different modes or sources of energy, these are the energy costs you projected including full amortization on capital costs, so there is close to 10 cents per kilowatt hour for CCGT at $3. Am I reading that right? Nuclear would be 16 or 17 cents per kilowatt.
Mr. Tenney: Yes, that's correct. On the first bar, I should point out that your $3 gas is with a carbon tax of $100.
Senator Massicotte: Our chairman knew the answer, but we are always debating the cost of the carbon tax. Even $100, which is probably what it would take to have a significant influence, it's an impact, but it is not bad from a percentage sense.
I think the producer association of Canada told us that when they do a capital project, given they don't know what the policy will be on carbon tax, that all of them factor in a significant carbon tax increase to make sure the feasibility is not going to be worked by some different government policy. Is that the case?
Mr. Tenney: I can speak from ATCO Power's perspective. When we're looking at building new power generation to replace our aging coal fleet, we're looking at all the technologies and trying to guess where a carbon tax will be. That will obviously influence what you might build. It's tough because some of these gas-fired assets are probably 25- to 30-year assets, and the hydro is probably a 75- to 100-year asset.
Senator Massicotte: When you price it in to determine the feasibility, because you make a serious error if you don't and you find the government policy has changed. What's the price of carbon you're assuming in your calculations?
Mr. Tenney: I'm not the one who is doing the business development for our combined cycle gas project so I'm not positive what they're using as the carbon tax; but they're certainly looking at it to say, "What will it be?" We have got solace in the fact that there is a big wedge of new power needed; so even if someone else built hydro, there will still be room for gas-fired generation to be built in there. Even if you're off on what you think the carbon tax is, it doesn't mean necessarily that the project is done because all your competitors are likely chasing the same technologies.
Senator Massicotte: Mr. Burpee, do you know what they're assuming?
Mr. Burpee: Most people will model anywhere from 25 to $100. I understand the sensitivity, but $100 is not out of the question at the high end. Even when federal regulations are reviewed, if it's a carbon impact, I know the coal-fired greenhouse gas regulations model in a social cost to carbons, which would effectively be saying $25 and another run at 100, just to see what the impact would be.
Senator Massicotte: In the North, it's a major endeavour, any hydro project, and therefore you must have government involvement. You also talk about basically a subsidy, financial assistance by the governments per se. We heard a lot of that two weeks ago saying it doesn't work. There are no numbers that work with any major project, so then you have the debate to say, well, should the rest of Canadians subsidize that project and to what extent?
Where do you stop? Does every Canadian deserve hydro power no matter where he lives? The answer is probably not, but how far does that argument go? To what extent should Canadians subsidize other Canadians, if they happen to live there or move there?
Mr. Tenney: If we go back to Muskrat Falls, I wouldn't say they had a subsidy, they just had a backstop arrangement so that if the project didn't get permitted, because there is a chance that a large-scale hydro project doesn't get permitted, it's more likely that a combined cycle gas project will get permitted; so there's a lot less development risks for it. On a large hydro, there is a chance that it doesn't get permitted. They had a fallback that customers would pay even if it failed. I think that's more what we're talking about, that there is a fallback position.
Senator Massicotte: I'm relieved. You're saying that Canadians will not need to subsidize these hydro projects in the future?
Mr. Burpee: I also say a loan guarantee really is not a cash draw. It just allows a lower financing cost.
Senator Massicotte: So there is no cost to that?
Mr. Burpee: In the case of most of these projects you know that any cost overrun will be borne by the consumer, or through regulated rates, some form of regulation, so the risk to the federal taxpayer is extremely limited, especially in hydro when there's low technology risk.
If you're doing a loan guarantee where there is high technology risk, as happened in the U.S. with solar manufacturer Solara that made all the headlines when it failed, there was a loan guarantee that actually cost the U.S. taxpayer because it was a technology failure.
With hydroelectric transmission there is no technology risk, but if you can effectively lower the borrowing and financing cost, that consumer then gets the benefit. It's not the project proponent that gets the benefit but the consumer that gets the benefit. I don't consider it a subsidy.
Senator Massicotte: So beyond the loan guarantee there is no need for any subsidization at all, not only in Muskrat but relative to future projects up North?
Mr. Burpee: We focused on what's possible in the Mackenzie Valley, so let's talk about some of the more remote communities that don't have that as an option. If you're in Nunavut you will not be able to benefit from that. The question is: Do you have other technologies in the long run that will be cheaper? Now you're getting back there and you do have technology risks. If it's putting wind in, which is happening in a few areas, then you need storage to go with it. You had a question earlier about where storage technologies are, and they are still evolving. Or do you go with tidal? It is another emerging technology and a lot of Nunavut is on coastline that has predictable tides. Again, you need some form of storage or they have some hydro opportunities.
Sustainable Development Technology Canada did support a number of projects looking at hybrid systems with the diesel, wind, hydrogen and other forms of storage, and government support. That's not billions and billions of tax dollars, but that's ongoing support for new technologies until you get to the point you know what the technology risk is, because it's somewhat unknown today, until you get past there and look at the economics to see if that's a viable option to diesel.
Senator Seidman: If I could ask you a bit about the smart grid, I think there is now a demonstration project in the North in Nunavut and Iqaluit. I think the Canadian Electricity Association released a report some years ago, Mr. Burpee, which had a degree of caution about smart grid. I would like to know, what's your impression of the current state now in the North, the demonstration project and the future potential?
Mr. Burpee: I don't know the specific one that's being referred to, but evolution in Canada of the smart grid is going very well and there is a lot of good work in Ontario, B.C., Quebec, New Brunswick and Saskatchewan is starting now, too. Everywhere has some element of it. A lot of it is when the smart meters were added in Ontario and the other provinces, it provided a lot more information as a starting point in terms of, hour by hour, who is using what and where to allow them to better manage the system. They're starting to put other monitoring devices so you get more real-time management of the system.
This will eventually evolve so we can better incorporate distributive generation, whether it's solar or others, to manage the system better, as well as electric vehicle charging. I don't think electric vehicles for the far North is an answer, but certainly the more we understand in terms of individual use and, going back to one of the things mentioned earlier, where you can get variable demand. I'm not sure I'd do it on diesel, but if we got to a point where we had more wind at a Northern community and can use hot water storage or heating units, you need a smart grid application to do that. The smart grid is not just the individual components but how to manage it as a system. Distribution management systems are getting quite a bit smarter. We really don't refer to it as "smart grid" anymore. It's just grid modernization, so it's an evolving process modernizing the grid.
Senator Seidman: You're saying it is evolving well and I would think it's clear that it's going to be necessary to develop new technologies to deal with the challenges in the North because there are serious issues there. As you've already said to us, the small customer base is an additional huge challenge, even though hydro is so optimal a solution in so many ways.
Could you tell us about your knowledge of the current research going into new energy technologies, specifically as they apply to North energy use?
Mr. Burpee: I'm trying to think. I looked at this STTC project list yesterday and saw at least five or six that were applied to remote communities and different combinations, whether it was storage, hydrogen, fuel cells, integration of wind and diesel and BC Hydro has some specific work under way. The Nalcor project is critical, and it will all be in terms of some of the existing technologies. The really evolving one would be tidal where you have in-stream tidal or hydrokinetic units rather than taking advantage of water that's already flowing. It sits on the bed of the ocean or a river stream and connects using kinetic energy of flowing water. It has a long way to go, but when you consider Canada's coastline, Ireland is a country putting a lot of money behind it. Canada has put a bit but not to the same degree. STTC is supporting at least three companies on top of the other projects.
Senator Seidman: Who makes the financial commitment to doing the kind of R&D that's necessary? As you say, we have the tidal, the rivers up North to supply a certain amount of hydro, but one needs to do the necessary research and development to bring it to fruition.
Mr. Burpee: The R&D comes out of some of the current manufacturers, universities and STTC plays a critical role at that startup phase so you're ready for early stage deployment.
If you have something where you can say you know what the revenue potential is, venture capital starts coming into it. But it's a lot of work to get to that point, especially in electricity, when the other options are so well-known. The other challenge, apart from isolated communities, is that in general the cost of electricity is very low in Canada. So to get into a whole new technology and through the period of technology risk when you figure out what works and doesn't requires a patient investor.
Senator Sibbeston: We were in the North, of course, in Yellowknife and had a whole day of hearings there and heard from N.W.T. Power Corporation and others. I don't know whether we heard from Northland Utilities that distributes power in Yellowknife, but hearing from them they gave us probably the best assessment in terms of the electrical situation for the people there, and it seems as if things are at a bit of a standstill. The mines could use power and all the adjoining communities could use cheaper power, but things are at a standstill because no one is willing to put their money into a grid, and there is uncertainty about the length of the mine. That's the situation.
What would you say your influence was? I'm wondering why you're here tonight in the sense that the answers are in the North and with respect to ATCO — the documents are all from ATCO — your role in the North at the moment is very limited to just distributing power in Yellowknife. I think you're involved in Providence and Hay River; is that right?
Mr. Tenney: Our community serves Yellowknife; distribution buys the power from the Power Corporation. In Hay River, we buy from the Power Corporation in the Taltson system. The other communities we serve — Dory Point, Kakisa, Wekweeti and Trout Lake — have diesel-fired generation. So we are looking at alternative energy to displace the diesel. Kakisa is one that comes to mind. It has a micro-hydro site that would work to displace the diesel fuel. However, it doesn't have storage, so you can't rely on it 100 per cent of the time, so you have to leave the diesel capacity.
At the same time, when you met with the Power Corporation and they talked about going around the west side of Great Slave Lake to connect into the Yellowknife, they would be building a transmission line that would go right past Kakisa. It seems kind of pointless to build a micro-hydro site when you might be connecting to a bigger hydro system.
So it's a bit on hold, but I believe the guys up there are still taking a look at it.
Senator Sibbeston: In terms of ATCO, do you hope to become a bigger player in terms of hydro, particularly of hydro power, in the North? You've obviously done some work and thinking in terms of looking at potential. From my perspective, you are not in the power-producing business — not very much — only in a number of small communities. The bigger ones are the N.W.T. Power Corporation.
So do you hope to become a bigger player in terms of hydro development in the North? You have some figures in terms of developing the Mackenzie and on the Bay River. If these projects ever come to fruition, they would be very big. Do you hope to expand your role in the North?
Mr. Tenney: The simple answer to your question is "absolutely."
Senator Sibbeston: I was also cognizant of the fact that people in the North are very sensitive about their rivers being developed — on the Mackenzie River and the Bay River. I know that examinations have been done with respect to the possibility of developing hydro on the Bear, but not so far on the Mackenzie that I'm aware. If anything ever develops on the Mackenzie, perhaps in the next 100 years or more, it would be up in the Fort Good Hope area where there is a drop in the river. There are rapids and high cliffs, so all the conditions seem to be right for development; would you say?
Mr. Tenney: I would agree with all of your statements. I recognize these rivers we're talking about are very controversial in terms of talking about these projects. I didn't have a chance to highlight that those numbers came from the Government of the Northwest Territories. They had a hydro strategy, I believe, back in 2008 or 2009, where they talked about the 11,500 megawatts.
But as you would know, when you're talking about the Mackenzie River, you're talking about the highway system. Putting a dam on the highway system isn't a good idea. However, in the fullness of time, things can change.
There are a lot of other rivers that are possibilities. For instance, the Taltson is a close one to where the Slave hydro site would be. I think there is upwards of 200-megawatts of potential on that river system. The Power Corporation looked at a 56-megawatt expansion.
You need to have a vision for it to ever be thought about, and I would say that ATCO's is a vision of a green energy corridor.
Senator Sibbeston: I notice the Liard River is not on a schedule of rivers. It's a major river, and I know that BC Hydro came into the North about a decade or maybe two decades ago, looking at that. It scared us a bit — the possibility of dam on the river. Certainly, I think the Liard River should be added.
Mr. Tenney: We tried to simplify it and make it as easy as we could. To be clear, I should add that ATCO has a long-standing history of engagement with Aboriginal communities, and it's a respectful engagement. In the North, if we don't have a genuine partnership, it's not like we'll come in and say, "We're building right here and that's the end of it." It will be in true partnership or it won't happen.
The Chair: I have a question for both of you. Our study is looking at the three territories, and Senator Massicotte talked about not subsidizing. The taxpayers of Canada — everyone; not just those in the territories — already subsidize the electricity in those small communities a huge amount to provide electricity. That will probably stay because of the small market. I understand those kinds of things and how spread out they are.
Maybe I misunderstood Senator Massicotte, but my opinion is that if it is a mine or something that large, there has to be a significant amount of capital put into it by whatever mining firm to actually backstop someone like ATCO going out and building something. I'm not here to say we shouldn't be subsidizing those kinds of commercial operations, but we do have to look at those smaller communities. They're basically all diesel. The numbers are here. You know them as well as I do.
What could be done to reduce the cost? The cost of electricity in some of those places is astronomical. Is there something we can do to reduce it? Do either of you have any suggestions? Is it new diesel generation that's a lot more efficient than the 40-year-old stuff? Is it a combination of other kinds of electricity generation? Give us some ideas.
We need to put in our report something that maybe the government could look at, because they already subsidize the diesel hugely — by 50 per cent, actually. In some places, it's $100 a megawatt; it's actually $200. When you put that one up there that's too expensive, that's what it costs in some of places. You know that. So give me some ideas.
Mr. Tenney: I will start, but Mr. Burpee will do a better job of explaining things in our global context. When we talked to the Government of the Northwest Territories, the economics are the economics. It's doubtful there is a magic solution that decreases the cost in some of these communities far from sources. But one of the concepts we thought might be worth considering is to have some kind of a partnership relationship with the GNWT, as we're chasing some of these large-scale hydro projects, for export back to southern Canada. You can use those profits to subsidize the high cost in those communities, because the load is fairly small, so it wouldn't take a lot of profits from large-scale hydro to be able to subsidize their electrical bills.
Mr. Burpee: The Canadian Gas Association has been in and probably talked about the merits of LNG versus diesel, so you've got that one. In the long-term, an internal combustion engine is not efficient and will not get efficient. It's a limitation of physics.
A lot of these communities probably already do a reasonable job recapturing waste heat, because the inefficiency in a diesel engine is heat that's created both in the water jacket cooling or from the exhaust gas. You can capture some of that heat and heat public centres. A lot of these communities probably already do that.
In terms of optimizing the existing system, there is probably not a lot of opportunity. Then it's different technologies all together, whether it's wind, tidal or some form of hydro. In each case, the operating costs should be reasonably low — at least the fuel costs are virtually nil. It's a question of high capital costs and subsidizing part of the high capital costs for a period of time. If you look at the chart that Doug used in terms of levelized unit energy costs, if you look at hydro over a long period of time, it's cheap. If you look at the initial shock of paying for the capital at the beginning, it looks expensive — as your horizon — 5 years, 10 years or 100 years.
But it goes back to having some form of vision for electricity supply that really has essentially low cost or free fuel, and you're limited in the technologies for that today. You also have to make a capital investment as well as the storage. You have to spend a lot of money and a lot of capital to save money in the long term.
The Chair: You spoke about tidal projects. My experience around tidal is that it's a long way from ever getting to a point where it's going to be affordable, even at the high diesel cost. Would I be correct in that assumption?
Mr. Burpee: I'll be careful not to take a position to agree with you, but I know a lot of people who would agree with you.
The Chair: So do I, so I'll leave it at that.
Mr. Burpee: It's technology that's unknown. Wind is better known, but the limitation of wind, to some degree, is that it gets really cold so that the people can't go up the towers if they need servicing. I think for Diavik, which has a wind diesel operation in the Northwest Territories, once it gets below minus 25, they can't go up. If it breaks below minus 25, they can't fix it until the weather warms up. That, hopefully, will change over time. Wind and existing hydro, whether it's run-of-river but you have a more conventional turbine, have much less technology risk than, say, tidal.
The Chair: For wind also, now that you've talked about it a bit, if it's the right weather, it takes a good part of the generation of the wind to actually keep the ice off the blades. That's all depending on the weather.
Mr. Burpee: That's one of the other issues.
The Chair: If it's moist and freezing, you don't get a lot of electricity. Hopefully, the wind is blowing and will keep the ice off the blades. There are some downsides to all of it. I know there's no silver bullet.
Mr. Burpee: We don't have silver bullets, no.
The Chair: I'm not asking for a silver bullet, but there could be some things out there. If there are other things, please let us know.
Senator Black: Following on the chair's question, is LPG an option, do you think, in rural communities in the North?
Mr. Burpee: I honestly don't have any data or background to understand the fuel costs and what the long-term commodity pricing risks on that are. So I'm sorry; I can't answer that.
Mr. Tenney: I don't have much to add. I would just caution you that a lot of those communities have no road access, so I'm not sure how they will get LPG in.
The Chair: They would get it in the wintertime on the winter roads. That's how they actually get the diesel.
Mr. Tenney: Right, and I don't know how long you can store LPG.
The Chair: You can store it indefinitely.
Senator Black: Following up on what the chair asked, I thought that, on the list of options, it was possibly an option.
Thank you, Mr. Chair.
The Chair: Okay, thank you very much. I appreciate that.
(The committee adjourned.)