Thank you very much, Mr. Chair.
I want to offer my sincere thanks to all the committee members this afternoon for the opportunity to provide my testimony.
My name is Wayne Stensby. I am the managing director for ATCO's electricity global business unit. For those of you who may be unfamiliar with ATCO, we are a proud Alberta-based leader in energy infrastructure development, with more than two million customers around the world, including over a million here in Canada.
It is our singular focus, day in and day out, to ensure reliable, accessible, and affordable energy. In doing so, we play a key role in enabling economic growth and the prosperity of the communities that we are privileged to serve. We are extremely proud of our long history of joint venture partnering, and in particular our partnerships with many of Canada's indigenous communities.
As I think about our Canadian operations, we own and operate electricity generation assets in Alberta, British Columbia, Saskatchewan, and Ontario. We operate an extensive system of more than 12,000 kilometres of transmission lines and over 75,000 kilometres of distribution lines in Alberta, the Yukon, and the Northwest Territories. Our newest business, ATCO Energy, is an electricity and natural gas retailer in Alberta.
As one of the very few publicly traded Canadian electricity companies that operate in Canada, with businesses across the entire electricity value chain and in multiple provinces and territories, we believe we are afforded a unique, holistic perspective on the potential for electricity infrastructure solutions that work to the benefit of all Canadians.
Indeed, when I consider the discussion point today, I note that we are presently constructing a 500-kilometre, 500-kilovolt transmission line known as the Fort McMurray west line, which we'll put into service in mid-2019. In 2015, we placed in service our eastern Alberta transmission line project, or EATL, which is a 500-kilometre, 500-kilovolt DC transmission line that serves to support the renewables build-out in Alberta.
With that backdrop, I am delighted to be speaking to you today specifically about strategic interties, which we believe offer a rare opportunity to achieve simultaneous positive outcomes across multiple areas.
The committee has requested that the witnesses address five specific questions. For these opening remarks, I'd like to take each of the five questions in turn, and then finish with a couple of additional thoughts.
The first question was about regional electricity independence. From our perspective, we believe the supply of electricity should be viewed using an overall systems approach, with an energy corridor across several provinces and to the north providing an important backbone that would enable the exchange of reliable and competitively priced electricity.
We would suggest that, rather than seeking regional independence, a strong overall strategy is to seek regional interdependence, working across provincial and territorial boundaries to ensure that the provinces and territories have an adequate supply of affordable, low-carbon electricity.
This interconnected grid could enable Canada to achieve a number of positive outcomes, including the reduction of reserves. Today, the provinces and territories each have the objective of providing reliable electricity under all scenarios. Therefore, each province and territory currently overbuilds generation capacity in order to meet scenarios of exceptional load. This results in a relatively inefficient system design, which incurs incremental costs that flow through to the consumer. If provinces and territories could instead draw from interties in order to facilitate some of these exceptional demand periods, some of this capacity could be avoided, and the savings realized by consumers. On a very high-level basis, we believe the avoided new-build capacity could represent a net present value of as much as $16 billion across Canada.
The second point is about increased resilience. As we face extreme weather events, and we note that they are becoming more frequent, an interconnected grid across regions improves resilience, making it less vulnerable to weather-related outages and reducing the time it takes to restore electricity following outages.
The third point is load diversity. Provinces and territories vary in time zones across our very expansive country and have staggered daily system peaks. lnterties enable provinces and territories to share capacity and meet the wave of peak demand as it moves from the east to the west across our regions. Provinces and territories could avoid the use of more expensive peaking plants that are presently in place today or wouldn't need to be in place in the future. Our very early high-level analysis would suggest that these savings could have potentially as much as $1 billion in net present value.
The challenge is of course that, given the wide variety of market frameworks, much consideration is required in order to land on methodologies that would allow the value to be distributed to all participants fairly and that it does not simply result in a wealth transfer across the borders of our provinces and territories.
With regard to the second question, low-carbon electricity distribution, in a typical year, both Manitoba and British Columbia export far more electricity to the United States than they do to other provinces. In fact, there are more than 30 major transmission connections between Canada and the U.S., yet there are relatively few interconnections of relatively limited capacity across the provincial territorial borders. While Manitoba and British Columbia have an abundance of hydroelectricity, Alberta and Saskatchewan are presently embarking on plans to significantly increase renewable energy and reduce the greenhouse gas emissions intensity of their grids. Interprovincial tie lines between these provinces would allow access to new and existing hydro resources that could have a powerful impact on meeting emissions targets across the country.
As well, there are many northern and remote communities that are meeting their electricity needs primarily through diesel-fired generation, with fuel that is transported either by a plane or across seasonal ice roads. Not only is diesel-fired generation uneconomic, adding to the already considerable cost of living in northern Canada, it is also at times unreliable. We firmly believe that reliable, cost-effective, electricity should be a basic element available to all Canadians. Given the abundance of current and potential hydroelectric resources in the west, and the opportunity to become grid-connected with the north, we envision that there are three high-level opportunities for the western provinces and territories, particularly, additional capacity and interties between Alberta and British Columbia, a larger scale Alberta-Saskatchewan-Manitoba intertie that would require an amount of direct current, and an intertie between Alberta and the Northwest Territories.
Question three refers to opportunities for alignment with the Canadian energy strategy. lnterties can facilitate the development of renewable energy resources to meet future demand. As Alberta, Saskatchewan, and other provinces and territories build out wind and solar projects, interconnection with the geographically separated or diverse renewables, or with dispatchable supply can provide important backup for intermittent generation. This allows the provinces and territories to avoid additional or unnecessary gas-fired generation that would otherwise be needed to meet the rapid changes in the intermittent renewable outputs. Our analysis, again at a very high level and very rough stage, would suggest that this could represent a net present value of roughly $1 billion for Alberta and Saskatchewan.
The fourth question is the Canada-U.S. energy trade and relations. To date, most generation and transmission planning in Canada has been largely confined within provincial boundaries and, of no surprise, has resulted in large efforts being taken, or undertaken, to provide export corridors to the U.S. lnterties that connect us east to west and allow the provinces to be more interconnected, and then through to the U.S. for export, provide additional opportunities. We don't see a conflict here; we see a benefit.
As well, interconnection across the country makes additional markets available to other provinces. Sales to neighbouring jurisdictions could indeed help finance or develop additional renewables in Canada.
The fifth question is employment and economic impacts. Interprovincial interties are large and long-lived infrastructure that bring high-quality construction operations and maintenance jobs to a number of regions for decades to come. Even more importantly, for the reasons I've outlined, interties help enable the provision of clean, reliable, and cost-effective energy for all Canadians. This underpins the economic vitality of our communities from coast to coast.
As an additional consideration, I would like to leave you with a couple of thoughts.
First, investments in capital-intensive, long-life assets like hydro generation and bulk transmission require long-term vision. That long-term vision needs to focus on the future benefits that these projects will provide. We encourage the decision-makers to look at the long term when weighing the opportunities today.
The second point is regarding timelines. There's a recent presentation from work done by NRCan that people are considering interties by 2030 and new hydroelectricity capacity by 2040. Our view is that these timelines are simply too long. Solutions to support renewable energy and modernization of the grid are required in the 2025 time period. The window of opportunity to realize these benefits can bring significant movement and significant opportunity if done today and not in decades to come.
Good afternoon, Chair, ladies and gentlemen, and honourable members of the Standing Committee on Natural Resources. My name is Brian Vaasjo. I am president and chief executive officer of Capital Power, headquartered in Edmonton, Alberta.
Capital Power is a developer, owner, and operator of generating facilities across Canada and in the United States. We are a publicly traded company with a market capitalization of approximately $2.7 billion.
Thank you for the opportunity to appear before you and to provide our perspectives on interties and their potential role in Canada's transition to a lower-carbon energy system.
As a participant and investor in electricity markets in Alberta, B.C., and Ontario, we are committed to working with governments at all levels in the assessment, design, and implementation of policies that can achieve public policy objectives for the electricity system in an efficient and effective manner.
Capital Power currently owns approximately 4,500 megawatts of power generation capacity in 24 facilities in Canada and the United States.
In Canada we have interests in 624 megawatts of capacity in Ontario from three wind facilities and two natural gas facilities. In British Columbia, we have 427 megawatts of generating capacity from a natural gas facility on Vancouver Island, two waste heat facilities, and a wind facility.
In the United States we have more than 1,100 megawatts of capacity in five states, including wind, solar, natural gas, and biomass.
The majority of our capacity is currently in Alberta. Capital Power has been the leading developer since 2004 and has ownership in nine facilities representing 2,400 megawatts of capacity, or roughly 14% of the Alberta market. Our Alberta fleet includes four coal generating facilities that are the youngest and most efficient coal units in Alberta, three natural gas peaking units, a combined-cycle natural gas facility, and a wind facility.
Alberta is unique relative to other provinces with respect to how generation investment occurs. This has little to do with specific market rules but relates to a fundamental distinction: that investment is made by private investors on an at-risk basis in a competitive market, and with no guarantee of cost recovery. While Alberta is undertaking a market redesign, the fundamental aspect of private investors bearing investment risk is expected to remain unchanged. This presents a significant issue for any consideration of strategic interties for Alberta.
Alberta's market redesign was in large part driven by Alberta's climate leadership plan, announced in November 2015. This plan introduced several policies to transition Alberta's electricity system to a lower-carbon trajectory. These included a phase-out of coal generation by 2030, introduction in January 2018 of a more stringent carbon pricing framework for large emitters, and a plan to add 5,000 megawatts of renewable generation by 2030 through a government-supported procurement program.
Capital Power was and remains supportive of the design and implementation of Alberta's plan and the emissions reduction objectives it's intended to achieve for our sector and province.
We worked with the Alberta government to reach a compensation agreement to reflect that the 2030 coal phase-out date specifically shortened the lives of six of our coal generating units. Alberta also reached agreement with two other Alberta counterparts who are also affected. This sent a positive message from Alberta in terms of investor confidence.
We are undertaking a $50-million program at our coal facilities to further improve their efficiency and reduce their emissions intensity by 10%. This responds to the signals for continuous efficiency provided by both Alberta's competitive market and its new carbon pricing framework.
We are actively exploring the potential for co-firing biomass at our coal facilities and are planning a second test next week. This would allow up to 15% co-firing at one of our units, resulting in immediate reductions in emissions.
We are also assessing design and economic issues associated with potential conversion of our coal units to natural gas prior to 2030. We are developing several wind and solar sites to participate in the competitive process to add 5,000 megawatts of renewables by 2030. We recently entered into commercial agreement with the Siksika Nation to develop projects on their lands.
We also stand ready to continue investing in the new capacity that Alberta will require to replace retiring coal generation and to meet load growth in Alberta and meet Alberta's renewable targets. We have a shovel-ready natural gas facility ready to go when market signals are appropriate.
The Alberta government estimates that the total level of power generation investment required by 2030 will be roughly $25 billion. The market redesign under way is intended to provide a framework to attract this scale of investment. This market will continue to rely on competitive forces and on investors making investments on an at-risk basis. It is in this context that the strategic interties, at least relating to Alberta, need to be considered.
The Alberta government set out three objectives for transition of the electricity sector in announcing their plan. These were maintaining reliability, providing reasonable sustainability in prices to consumers and business, and ensuring that capital is not unnecessarily stranded.
Capital Power believes there are five objectives and considerations that should be incorporated into the assessment of government-funded intertie projects.
First is reasonable costs. Any federal initiative needs to ensure reasonable costs for consumers. The costs associated with strategic interties would include the costs associated with new hydro resources developed to backstop the interties, new generation that would be required in Alberta or any “sink” provinces to provide reliability when hydro imports might not be available for any number of reasons, and direct costs to expand both intertie and provincial transmission grids to manage energy trade in real time.
Capital Power does not believe that the all-in cost of a strategic intertie would be a lower cost, from a ratepayer perspective, than low-emitting and renewable generation developed in Alberta.
Second is reliability considerations. The reliability issues raised by a strategic intertie based on construction of new hydro sites need to be considered. First, the announcement of an intertie would make an immediate impact upon investment decisions in Alberta by reducing the future market opportunity. A single large intertie creates its own significant risk from the standpoint of reliability.
Third is environmental outcomes. Any federal initiative needs to ensure that assessment of environmental outcomes takes into account whether the intertie would be supported exclusively by hydro or non-emitting generation or would be utilized to “wheel” power from other markets. Alberta's existing interties, including the one with B.C., are used to import power sourced from markets with thermal and renewable supply sources. A strategic intertie initiative that expanded the scope for wheeling of thermal generation from outside the province would not provide any benefits from an emissions perspective.
Fourth is community benefits. Federally subsidized intertie projects would displace and pre-empt investment in low-emitting and renewable capacity in Alberta. In doing so, they would also diminish the opportunity for Albertans and Alberta communities to realize the benefits of locally sited generation that will be required to replace retiring coal generation and meet demand growth. This is a particular issue for Alberta communities in which coal facilities are located, but also an issue for communities looking for the opportunity to host renewable energy projects.
Fifth is a level playing field and investor confidence. As noted, Alberta's market will continue to expect investors to bear risks of investment decisions and to seek a return through a competitive market. A federal initiative to subsidize imported supply will create an unlevel playing field for Alberta-based generators. Ensuring fair treatment of existing investments must be considered for any federal initiative, in the same way that Alberta has established this as a principle for its market redesign initiative.
In respect of Canada's 2050 vision, as a final comment Capital Power notes that the Government of Canada's 2050 vision identifies a role for several sources of non-emitting power generation, including hydro, nuclear, and carbon capture and storage.
Consideration of strategic interties needs to be coordinated with the assessment of those options to ensure that any federal funding is targeted to support the lowest-cost option. In this regard, Capital Power believes that any funding or procurement process to support non-emitting technology should not be fuel-specific but should instead invite proposals from industry on options that can meet the non-emitting criteria.
Successful proposals would be those that would meet objectives in a most cost-effective manner. Proceeding with strategic interties in isolation would close the door on other technologies, such as carbon capture and storage, that may be more appropriate and cost-effective for Alberta over the long term.
In closing, government support for intertie projects, while in certain jurisdictions could be a source of public good, in others might have unintended consequences with respect to consumer costs, reliability, and investor confidence.
Capital Power is a Canadian company that wants to continue to invest in our power infrastructure to support the transition of Canada's electricity system. We are not asking for any advantages or special programs or benefits. We are asking that the government not embark on programs that disadvantage us.
Capital Power appreciates the opportunity to provide its views on this very important initiative.
I think, just from the highest level and a principle perspective, probably any answer to what is done with the energy mix would suggest that you need some diversity. You can't be all hydro. You can't be all nuclear. The wisest thing to do is to have some diversity around that.
Each region in Canada has its own resource base. Alberta has been historically blessed with hydrocarbons. Obviously British Columbia and a number of the other provinces have very tremendous hydro resources, and they've developed their resources accordingly.
When you look at what might be the answer, what might be the build in the longer term, as basically communicated and positioned by the Canadian government, hydro is a significant part of the Canadian future in power generation. Most of the work is suggesting that hydro power in Canada has to double. I think we'd agree with that. That it is definitely a renewable resource and is, to some degree, readily available.
That, in combination with interties, can't be the only answer. If you take Alberta, southern Alberta has the best solar resource in Canada. It has a tremendous wind resource. There's a tremendous amount of renewable energy, green energy, that's available other than hydro. There continues to be good strong hydro potential in Alberta, as well.
Each region has its own unique characteristics, and in each region there is likely a different answer. Some of that answer may well be interties. Certainly I would agree that connections to northern Canada definitely have some tremendous benefits. The intertie between Alberta and B.C. today is derated, and should basically be doubled in effective capacity through improvements.
There's definitely a lot of work that can be done around interties and around transmission. The unintended consequence is when there ends up being an answer arrived at and you end up with overreliance on a particular source or particular intertie, or whatever. That creates a significant risk of a different nature. That's a part of the unintended consequences, and specifically when you look at the Alberta market.
When it was announced that there may be an intertie between Alberta and B.C. and that Site C power would go there, it had implications for our market. In the long run, people are looking at that and asking how they can build an asset and all of a sudden be swamped by hydro energy coming from British Columbia, which crashes the market.
There are some definite consequences associated with it.
Good afternoon, Mr. Chair and committee members. Ms. Milutinovic and I appreciate the opportunity to appear before you today.
I'd like to open by familiarizing the committee with the National Energy Board's mandate with respect to electricity. The production of electrical energy in Canada and much of the infrastructure and trade in electrical energy are constitutionally within the powers of provincial governments, so the NEB's mandate on electricity is quite limited. The mandate we do have comprises two broad categories: an adjudicative function and an energy information function. We believe both are somewhat relevant to your study today.
There are two separate aspects to the adjudicative function. The first relates to power lines. A company seeking to construct or operate an international power line, or IPL, can apply to the NEB for either a permit or a certificate. The board always seeks public input for an IPL application. Under the permit application, the board hears concerns from stakeholders, but after they hear concerns, they are required to issue the permit under the NEB Act, although the board can attach conditions to the permit. Once permitted, an IPL is subject to regulation by the province it is in, if an energy regulator exists in that province. Should the board receive comments that somewhat concern it as a result of the permit application, the board can recommend that the IPL be designated for the certificate process by the Governor in Council.
A company can also apply directly for a certificate. Under the certificate process, the board can hold a hearing and approve or deny the IPL application based on the evidence gathered. The ultimate approval under the certificates process is subject to the Governor in Council.
The NEB has no automatic authority for the regulation of power lines that cross provincial or territorial boundaries. That said, the Governor in Council has the authority to designate an interprovincial line to be under NEB regulatory authority. Currently, the NEB does not regulate any electricity transmission lines that solely go between provinces.
The second aspect of our adjudicative process deals with trade. Exporting electricity to the United States requires a permit or a licence from the National Energy Board. The current default process is the permit process, which begins with a public comment period under which the board will consider factors such as the effects of the export on adjacent provinces and fair market access for Canadians. If the board has concerns, it can recommend that the application go to a licence process, which requires a hearing. If the permit process prevails, though, the NEB will issue a permit. Under the licence process, the board can approve or deny the application after the hearing. Approvals are subject to Governor in Council approval as well.
Since the permit process was introduced in the early 1990s, all export authorizations have been under permits rather than licences. With both permits and licences, the board has the authority to attach terms and conditions. For example, the board requires companies to submit monthly reports on the volumes traded. The NEB Act allows electricity export permits to endure for up to 30 years.
The NEB has no mandate for the regulation of electricity imports, nor for interprovincial electricity trade.
Beyond our adjudicative function, the NEB contributes to the national energy conversation by providing neutral, independent, and fact-based information to Canadians. The NEB's energy information program includes the collection, analysis, and publication of information on energy markets, including electricity. We regularly publish energy information reports, ranging from very brief targeted energy market snapshots to more comprehensive larger reports. These products increase the transparency of the Canadian energy market, support energy literacy, and inform Canadian decision-makers.
We will soon be releasing the latest edition in our energy futures series, entitled “Canada's Energy Future 2017: Energy Supply and Demand Projections to 2040”, or simply, “Energy Futures 2017”. Our energy futures reports are the only publicly available long-term Canadian energy outlooks that cover every energy commodity in all provinces and territories. An interesting fact is that next week's report comes 50 years after we published our first such report in 1967.
“Energy Futures 2017” will look at how possible energy futures might unfold for Canadians over the long term by considering three cases: a reference case, which is based on the current economic outlook; a moderate view of energy prices; and the climate and energy policies that were announced at the time the analysis was done.
A higher carbon price case considers the impact of higher carbon pricing than in the reference case, and our technology case considers the impact of greater adoption of select emerging technologies that impact energy production and consumption.
Technologies include less expensive solar and wind electricity generation, grid-scale battery storage, electric vehicles in the passenger transportation sector, steam-solvent technology for the oil sands sector, electrified space and water heating in the residential and commercial sectors, and carbon capture and storage technology for coal-fired electricity generation.
I'd like to point out a few key statistics with respect to renewables in Canada. Canada has a wealth of electrical generation capacity. Fifty-five per cent of Canada's capacity and 58% of our generation are from hydro. Non-hydro renewables account for 12% of capacity and 7% of generation, and coal, nuclear, natural gas, and oil round out the rest.
We've provided some slides to the clerk on non-hydro renewable capacity and generation projections, as well as Canadian end-use demand according to the three scenarios in our upcoming energy futures report. That's a bit of a spoiler for the energy futures report, as interesting as it might be.
Electricity generation varies greatly across provinces. For example, hydro accounts for 95% of electrical generation in Quebec, Manitoba, Newfoundland and Labrador, and Yukon, and 87% in British Columbia. Conversely, virtually none of Nunavut's power is hydro-generated. Instead, Nunavut relies heavily on diesel generation. Nuclear power generation, at 15%, is Canada's second-largest source of generation. However, it is concentrated in only two provinces, Ontario and New Brunswick.
A notable trend over the past decade has been the increase in the generation capacity for renewables such as wind, solar, and biomass. Non-hydro renewable energy has increased its national share by almost five times since 2005. In fact, according to our projections, renewables' share of generation capacity is expected to grow even more in the future, with wind capacity more than doubling and solar capacity more than tripling by 2040 in our latest reference case scenario.
In conclusion, the board stands ready to assess any electricity applications that are filed with it, and we will also continue to provide fact-based energy information to inform the energy debate in Canada.
With that closing, I'll thank the committee again, and we're open for questions.