I'd like to call the meeting to order.
Welcome to meeting number 23 of the Standing Committee on Natural Resources, and the second meeting in our current study.
To our witnesses, I just want to say thank you for coming and welcome. Some of you may have been here before, but for those of you who haven't, it's obvious that we're doing this in a virtual format, which brings with it certain challenges. We need to be patient when others are speaking and not try to speak over others, and make sure that other people have finished talking before you speak—all of the things our mothers taught us when we were young children, basically.
If you need translation, there's a button at the bottom of your screen that should provide that for you. You're welcome to and encouraged to speak in either or both official languages. You will almost certainly be asked questions in both. If you're having any challenges, please feel free to raise your hand or raise your voice.
My job, in part, is to keep track of time, which means that from time to time I may have to interrupt and stop people for going over the time limits. We do have time limits for introductory remarks and questions.
Having said that, each witness group will be given up to five minutes to make opening remarks and then, after all of the witnesses have finished, we open the floor to questions. All of our witnesses are here, with the exception of Enbridge, which hopefully will be joining us in due course.
Welcome everybody. We have Énergir, Enerkem, Evolugen and Fortis Inc. I think it probably makes sense if we just start in the order that you appear on the agenda, in which case, Ms. Trudeau, you will be starting us off for five minutes.
Good afternoon, Mr. Chair and members of the committee.
Thank you for inviting me.
My name is Stéphanie Trudeau, and I am the executive vice-president for Quebec at Énergir.
To begin, I'll say a few words about Énergir.
Énergir is Quebec's largest natural gas distributor. I am proud to say it now has a significant presence in the energy sector. In the early 2000s, nearly all of Énergir's operations revolved around natural gas distribution, but over the years, the company has diversified its energy portfolio. For example, in Quebec, Énergir owns one of the largest collections of wind farms in Canada. In the United States, through our subsidiaries, we produce and distribute hydroelectricity, wind power and solar energy. In both jurisdictions, Énergir now distributes renewable natural gas, and today, the production and distribution of renewable energy accounts for approximately 50% of Énergir's assets, totalling more than $8 billion.
Our business model for gas distribution has evolved and will continue to evolve. Over the past 18 months, we have developed a corporate vision for 2030 and 2050, which should help us become a provider of varied and increasingly renewable energy solutions. We want to stay relevant for our customers and society, which is on a clear path to accelerated decarbonization. We want to be part of the solution.
Further to this strategic shift, we have adopted four overarching policies, all aimed at decarbonizing our natural gas network more and more and growing our presence in areas where we can add value. I will list all four policies quickly and revisit two of them in greater detail.
The first policy is, of course, to step up our energy efficiency initiatives. That is a must, and Énergir has been a pioneer in the area for the past two decades.
The second policy is to accelerate the injection of renewable natural gas, or RNG, into our network. We have already been active on that front for more than 10 years. RNG is a key component of decarbonizing the energy we distribute. I will come back to this point.
The third policy is to significantly leverage the complementarity of the gas and electric networks. The idea is to take full advantage of Énergir's and Hydro-Québec's existing energy infrastructure to decarbonize the networks at the lowest cost to society.
The fourth policy is to diversify our operations through sustainable growth vectors. For example, we are looking at injecting hydrogen into the network to further reduce the carbon content. I will come back to this point as well.
Under this plan, we aim to reduce the greenhouse gas emissions, or GHGs, of our builder customer base by 30% by as early as 2030. Next, we are aiming for carbon-neutrality in our energy distribution by 2050. Énergir is working extremely hard to encourage the development of the RNG sector in Quebec. By 2030, we are aiming to inject at least 10% of RNG into our network, and we are on the right track. So far, we have about 20 projects in the production, construction or development stage.
You may be wondering, and perhaps rightly so, whether these efforts will be met by demand. I can tell you that, right now, we are not doing any active marketing and demand is outstripping supply. Customers recognize not only the environmental benefits of RNG, but also its competitive pricing as compared with other types of renewable energy. RNG is an extremely effective way to decarbonize Canada's gas networks. Énergir also believes in the importance of exploring other energy sources, such as hydrogen. Gas infrastructure can actually be used to effectively store and distribute hydrogen, and we are currently examining how the network could be used for that purpose.
I would like to conclude with a few suggestions to support the development of renewable natural gas and hydrogen.
First, support for production is key. That support could take the form of regulatory incentives, for instance, through minimum content requirements, similar to what the Quebec government has done for RNG. Other options are to provide support for R and D, and pilot projects that help foster a Canadian ecosystem. Support for demand is another important avenue. Governments can play a central role in changing consumer habits, especially by adopting procurement policies and leading by example. I would go so far as to say they have a duty in that regard.
The Department of National Defence is making a significant contribution through its Quebec-based facilities, which rely heavily on RNG. Other federal departments and agencies should follow suit and make the switch; not only is RNG competitive and renewable, but it also requires no new equipment.
Énergir has no doubt that renewable, low-carbon fuels hold tremendous potential for Canada, because they can significantly enhance the country's environmental performance at a competitive price. As an energy distributor, we have the expertise and infrastructure to advance that effort. We believe that diversified energy sources are the key to a strong green economy.
I would be pleased to answer your questions.
My name is Dominique Boies, and I am the chief executive officer of Enerkem. Thank you for inviting me to meet with the committee today. I am pleased to contribute to your study on the future of the low-carbon and renewable fuels industry.
To start, I'd like to give you some background on Enerkem. Established in 2000, Enerkem has developed and commercialized a one-of-a-kind disruptive technology to produce low-carbon advanced biofuels and renewable chemicals from non-recyclable waste materials.
Our technology is an integral link in a true circular economy, contributing to the diversification of the energy portfolio and the production of greener mainstream products, while providing a smart and sustainable alternative to landfill and incineration. To achieve this level of technology maturity, Enerkem raised more than $850 million in capital, largely through private and foreign investment.
On December 8, with a group of strategic partners including Shell, Proman, Suncor and Hydro-Québec, and with the support of the governments of Canada and Quebec, Enerkem announced plans to build a biofuels plant in Varennes at a cost of $875 million. Recyclage Carbone Varennes will produce biofuels and renewable chemicals from non-recyclable waste materials and forest biomass. The plant will actually convert more than 200,000 tonnes of waste per year into more than 125 million litres of biofuel annually.
Now, I would like to tell you a bit about the context in Canada and around the world. I don't want to throw too many statistics at you, but according to the World Resources Institute, in 2018, Canada was the 10th largest GHG-emitting country or region. Canada's GHG emissions continue to rise despite current measures.
Last week, Prime Minister Trudeau committed to reducing GHG emissions by 40% to 45%, a much more ambitious target than the one in the Paris agreement. Canada also committed to a carbon-neutral economy by 2050.
Canada has made strong commitments to reduce GHG emissions, but achieving those targets first requires taking stock of the situation and creating the right conditions.
Where do things stand? In terms of transportation, electrification support and initiatives are commendable, important and necessary, but will not be enough to significantly reduce Canada's GHG emissions.
Canadian gross sales of gasoline totalled 44.8 billion litres in 2019, with no significant decrease in recent years. Vehicle registrations in 2019 totalled 36 million. Today, Canada's total vehicle fleet includes fewer than 200,000 electric vehicles, or 0.5%.
Now that the targets are set and the state of play is known, it is time to take action.
Here are some important considerations. When it comes international markets and the appetite for low-carbon biofuels, the Canadian marketplace is less attractive given the lack of both minimum content regulations for biofuels derived from waste materials and a low-carbon fuel standard, or LCFS. For instance, the United States has the renewable fuel standard, California and Oregon have the LCFS, the European Union has the RED II to promote the use of renewable energies, and the United Kingdom has the renewable transport fuel obligation. All of those jurisdictions have already put ambitious standards in place to force fuel distributors to increase their supply of low-carbon biofuels made from waste.
These types of standards create the right market conditions for producers. For instance, a litre of methanol or ethanol produced at our Edmonton facility now goes for double in California and nearly four times as much in the United Kingdom, including transportation costs. Without a competitive regulatory environment in Canada, keeping low-carbon biofuels in Canada will be a challenge.
Unlike incineration, which burns waste and uses energy, Enerkem's gasification platform recycles carbon and hydrogen from waste into biofuels and renewable chemicals.
We offer a true green alternative to landfill. For instance, our new plant in Varennes will help reduce GHGs in Quebec by 170,000 tonnes of carbon dioxide equivalent annually. Imagine what 10, 15 or 20 plants could do.
In an effort to be constructive, I would like to share some recommendations.
If Canada is going to achieve its ambitious GHG reduction targets, it must create favourable market conditions to support the application of innovative solutions. A carrot and stick approach is necessary. When it comes to the carrot, Canada does not have to reinvent the wheel.
Many tools and programs have been used successfully in other industries such as green electricity, oil and gas, and mining. For example, governments have reduced the risks of early wind farm development by offering long-term power purchase agreements. It is necessary to create a competitive Canadian market to attract foreign private investment and support bioenergy projects.
Thank you to the members of the Standing Committee on Natural Resources for inviting me to take part in its study on the low-carbon and renewable fuels industry.
I'm delighted to appear before you today to discuss the important role low-carbon and renewable fuels can play in Canada's decarbonization targets and the creation of economic opportunities.
First, allow me to introduce myself. My name is Frédéric Verlez, and I am the senior vice-president of business development and strategy at Evolugen. I oversee the business strategies related to Evolugen's assets, the company's growth through acquisitions, and the development of and investment in new technologies.
Evolugen is the Canadian operating business of Brookfield Renewable, which established its first publicly traded entity in 1999, in Gatineau, Quebec, with three hydroelectric stations located along the Lièvre River, in southwestern Quebec. Those assets have been operational for more than a century. Through its companies and subsidiaries, Brookfield Renewable now has a portfolio of 20,000 megawatts in installed capacity and approximately $50 billion in assets under management, making it one of the world's leading renewable energy platforms.
In Canada, we own and operate 61 renewable power facilities—producing hydroelectricity, wind power and solar energy—for a total of 1,900 megawatts in installed capacity. Our facilities are located in Ontario, Quebec and British Columbia.
While we have traditionally focused on renewable power, we recognize that decarbonization will require diverse and sustainable solutions focused on accelerating the transition to a low-carbon energy future. We're currently working to expand our role into broader decarbonization solutions to help our partners achieve their carbon reduction goals.
One such example is low-carbon hydrogen. Recently, we announced our collaboration with Gazifère, an Enbridge company, to develop one of Canada’s largest renewable hydrogen injection projects, to be located in Quebec. As part of this joint effort, we shared plans to build and operate an approximately 20-megawatt water electrolysis hydrogen production plant in the Outaouais region. This plant will use renewable electricity from our Masson facility to produce renewable hydrogen.
This will be the first large-scale project in Quebec and Canada to produce renewable hydrogen for injection into a natural gas distribution network, a model with significant expansion potential. In Canada, there is a high potential market depth for low-carbon hydrogen given broad use across hard-to-abate and carbon-intensive industries.
The facility will generate considerable environmental and economic benefits regionally, provincially and nationally. Specifically, the project will avoid approximately 15,000 metric tons of greenhouse gas emissions per year, in addition to generating significant local economic benefits, including new jobs and additional property tax revenue. Over time, our focus will be on expanding to additional end uses and replicating this model at other facilities, including new renewable power facilities dedicated to hydrogen production.
We believe that our hydrogen efforts are in line with the policy objectives of the Canadian federal government and those of many provinces across Canada, which have been expressed through carbon reduction targets, hydrogen strategies and clean fuel requirements. In the current environment, hydrogen can also play an important role in our post-pandemic economic recovery, stimulating investment and job creation.
That said, seizing Canada’s hydrogen opportunity is not without challenges, and the involvement of governments is necessary to maximize this opportunity. Specifically, we see a role for government in creating clear, straightforward and responsive policy and regulatory frameworks for hydrogen production, distribution and end use, with an initial focus on near-term applications; helping to reduce production cost through direct investments and creating value streams for low-carbon fuels; helping to overcome technological and cost barriers associated with transporting hydrogen, such as through the creation of shared-use infrastructure; supporting end-use uptake; and, finally, facilitating access to financing. We strongly believe that by working together with governments and all industry players, Canada can become a leader in the production and use of low-carbon hydrogen and biofuels.
Thanks again to the committee for allowing me to speak today. I look forward to the opportunity to answer your questions.
Good afternoon, Mr. Chair, and members of the committee. Thank you for the invitation to speak to you today.
I would like to begin by acknowledging Fortis's respect for indigenous peoples in this place we call Canada, and on whose traditional territories we all live, work and play. Fortis has long supported engagement with indigenous communities and building strong relationships based on respectful dialogue that creates mutually beneficial opportunities.
At Fortis, our core responsibility is to deliver safe, reliable and affordable energy in an environmentally responsible manner that respects the communities we serve. These values are reflected among the five companies that we operate across Canada—in British Columbia, Alberta, Ontario, Prince Edward Island, and Newfoundland and Labrador—as well as those we operate outside Canada. Across North America and the Caribbean we deliver energy through 10 utility operations to more than 3.3 million customers.
As an organization operating both electric and gas utilities across the continent, we have unique expertise and perspective to inform energy and climate policy.
We believe that achieving the national targets identified by the Government of Canada is a shared responsibility. We recognize the important role that we play in supporting efforts to combat climate change, investing in the transformation of Canada's energy infrastructure, and supporting the advancement of indigenous peoples.
Our Waytaynikaneyap Power partnership with first nations in Ontario, and our corporate-wide target to reduce carbon emissions are two examples of our commitment in action. We are targeting to reduce scope 1 emissions by 75% by 2035, from a 2019 base year. That target is now driving our investment plans, with more than 70% of our $4.3-billion 2020 capital plan dedicated to asset resiliency, modernization and cleaner energy initiatives.
A further example is in B.C., which remains a leading jurisdiction in North American climate policy. Our local utility, FortisBC, provides both electricity and natural gas to over 1.2 million homes and businesses across the province. Two years ago, FortisBC launched their plan to reduce emissions, called the clean growth pathway to 2050. This plan outlines numerous actions that will contribute substantial reductions in greenhouse gas emissions by harnessing the decarbonization potential of their gas and electric delivery systems.
Included in these actions is a stated goal to aggressively increase the supply of renewable natural gas in their system and advance hydrogen development. By 2050, FortisBC envisions a future where the majority of gas within their system will come from low-carbon and renewable sources. Many of these actions are reflected in the provincial climate strategy, CleanBC, including a target of 15% renewable content in the gas stream by 2030.
With this as background, the following recommendations merit consideration of the committee as it deliberates on these matters.
The first is to recognize the massive potential of the gas system to deliver emissions reductions. We recommend continued support for the growth of Canada's renewable gas sector with a policy that preserves a role for natural gas in the building space. We should develop a made-in-Canada pathway that leverages our existing gas and electricity infrastructure to achieve net zero and make Canada a global leader in renewable gases.
As I mentioned, B.C. has established a 15% renewable gas mandate for 2030 as part of their CleanBC climate strategy. FortisBC has been delivering renewable gas to their customers for more than a decade now. This single action within CleanBC will deliver more than three-quarters of the emissions reductions in the building space outlined in B.C.'s climate plan.
FortisBC is well on track to meet and exceed this target through near-term investments in biomethane and developing medium- and long-term pathways to develop B.C.'s hydrogen resources. This is why policy must preserve a role for gaseous energy delivery so that the benefits of these low-carbon fuels, using the strong infrastructure that exists, can be realized through their delivery to customers.
FortisBC commissioned Guidehouse, a respected global consultancy, to enable our utility to engage with and support an actionable decarbonization strategy for B.C. FortisBC undertook this project because they knew we needed specific made-in-B.C. pathways that reflect the unique constraints and opportunities of a winter peaking system and to decarbonize as quickly and cost-effectively as possible.
The results show that a diversified pathway can achieve our long-term emissions reductions targets with lower costs and lower risks to society. A diversified pathway that uses both our existing gas and our electric infrastructure is shown to be less economically disruptive, while also maintaining energy affordability and resiliency for our customers. In the same way that the electric grid allows for increasingly low-carbon electrons to be transported, the natural gas grid should be viewed as a way to enable increasingly low-carbon molecules to be transported.
Second is to provide clear policy signals on the role of the gas system in the net-zero environment. We recommend policy development that provides clear support for investment in long-lived energy infrastructure in Canada and for the role of innovation.
Climate policy, energy policy and on-the-ground operations are under constant transformation, while energy infrastructure has long planning lead times, long service lives and significant cost. In order to meet our needs and climate imperatives in 10, 20 and 30 years from now, we need clear policy signals on a complex landscape, including renewables, transmission and natural gas. That's required today. Ambiguity forestalls innovation, investment and actionable, achievable business changes. The energy transition is occurring—
Mr. Chair and members of the committee, I want to thank all of you for undertaking this study of the low-carbon and renewable fuels industry and how we might work together to advance these industries in Canada to create new jobs and maintain energy security, reliability and affordability, all while addressing climate change, including our country's recently announced goal of reducing greenhouse gas emissions to 40 to 45% below 2005 levels by 2030.
In our view, low-carbon and renewable fuels will be a significant part of Canada's low-emissions future.
My name is Cynthia Hansen and I'm the EVP and president of gas distribution and storage at Enbridge. I'm fortunate to lead the Ontario-based Enbridge Gas Inc., which follows the amalgamation of Enbridge Gas Distribution and Union Gas, as well as Gazifère, which serves the Gatineau region of Quebec.
With me is Jean-Benoit Trahan, the director of Gazifère.
Enbridge operates North America's largest natural gas utility by volume, and the third largest by customer count. Enbridge Gas and its affiliates deliver safe, reliable service to about 15 million people in Ontario and Quebec through 3.8 million residential, commercial, institutional and industrial meter connections.
We've been delivering energy for over 170 years, so our perspective on the promise of Canada's low-emissions future is informed by decades of experience. My comments today will focus on hydrogen and renewable natural gas, or RNG.
Enbridge was an early investor in both hydrogen and RNG, and is very experienced in RNG. On the hydrogen front, our journey started in 2011 when we partnered with Cummins Inc., formerly Hydrogenics Corporation, to establish a collaborative joint venture to create and advance the renewable hydrogen market in Ontario and, more broadly, North America. The culmination of this joint venture was the construction of the first and largest power-to-gas renewable hydrogen plant in North America, located in Markham Ontario.
The plant was a platform for Cummins to showcase its world-class, leading proton exchange membrane electrolyzer and fuel cell stack technology. For us, it's an important expansion of our renewable energy portfolio, establishing and growing the market.
This past November, we announced the next phase of our hydrogen journey in Markham—a $5.2 million project, supported by Sustainable Development Technology Canada, to blend renewable hydrogen gas into our existing gas network. This project will be the first of its kind in North America, and will be in service this fall. This project will unlock additional value in our larger-scale hydrogen blending activities in other parts of our distribution system.
In Ontario, we have a number of exciting hydrogen opportunities under development. We're looking at leveraging our four strategically located compressed natural gas stations along Highway 401 to create a green hydrogen corridor.
We are approached regularly about new hydrogen projects. We're looking at bus refuelling facilities, new power-to-gas opportunities, and several mobile and stationary power generation applications. We see opportunities in other parts of the country as well, including with B.C.'s gas transmission and distribution system. Further, the opportunity to decarbonize Alberta's oil sands through a carbon capture utilization and storage solution that is fully integrated with ambitious plans to launch a local blue hydrogen sector is very exciting.
In Quebec, as my colleague Jean-Benoit can explain, Gazifère aims to be North America's first natural gas utility to be 100% green by 2050. Hydrogen will play a large part in that, which is why, in February, we announced, along with our partner Evolugen, a new $90 million, 425,000 gigajoule green hydrogen injection project. We agree with Canada's , Minister O'Regan, that hydrogen's time has come. However, steps will be needed to take this opportunity.
Finally, on renewable natural gas, we're involved in three significant RNG projects in London, Niagara and Toronto, Ontario. We're a partner in a biorefinery project in Lacombe, Alberta, and we've recently celebrated the launch of Ontario's first carbon-negative RNG bus in Hamilton. We've also launched an important voluntary RNG program for our customers in Ontario to empower households to lower carbon emissions. Just this Wednesday, we announced a major new partnership to execute projects in Ontario that convert organic waste into energy and utilize current Enbridge infrastructure to heat homes, power business and fuel fleets, all while reducing carbon emissions.
We've done a lot in the hydrogen and RNG space today, but much more could be done with government support, including strategic investments and the proper regulatory and tax environment.
I'm very much looking forward to the conversation over the next hour and a half. Thank you again for your time and leadership.
Thank you, Mr. Chair, and thank you to the witnesses. My first question is for Fortis.
I calculate the price today for ATCO gas, the Alberta natural gas blend, as about $2.50 per gigajoule of energy. Using a 100% blend of renewable natural gas, for a business that burns over 3,500 gigajoules per month, you're looking at an increase to their heating bill of over 2,000% right now. That goes across the board. Residents would pay an increase of over 2,000% if they were to have 100% renewable natural gas.
How do you think businesses and residents are going to be able to afford this, and how many years do you think it will take for renewable natural gas infrastructure get gas down to a reasonable price for Canadian businesses and consumers?
Thank you, Mr. Lloyd. That's a great question and one that we talk about quite often.
You have to make sure, in the transition to cleaner energy resources, that you are absolutely focused on customer affordability, and when you set climate policy and realize that you have to reduce the amount of carbon that you emit as a society, there are only so many options that you have. What we typically talk about is the balance of those options between things like renewable natural gas and hydrogen from a fuel perspective that you can transport in a gaseous phase, and electricity. What you have to compare is not necessarily the cost between, say, renewable natural gas and natural gas—methane in B.C.—coming right out of the ground, but to compare that to the other opportunities, which are going to be things like carbon capture utilization and storage or electricity.
It's really shifting the paradigm of what you compare those costs to, and yes, you're absolutely right, when you look at the cost that we see for renewable natural gas now, it is in that $20 GJ number range that you brought up. If you look at the cost of gas coming right out of the ground, it is in that same range that you talked about, which is, depending on the market conditions, anywhere between let's say $2 and $5 a GJ.
That's the picture that we have to see clearly so that we can make those trade-offs and make them cost-effective for our customers. At the end of the day, what you're looking at is comparing renewable natural gas as a heat source delivered to our customers, burner-tip costs, to the same thing that they would need to get electricity from, say, renewable or hydro—whatever that clean energy is—transmitted to those customers for that same purpose. That's how the economics have to be compared.
Thank you very much, Mr. Chair.
First of all I'd like to thank all of the witnesses. This is our second meeting on this study. I am incredibly impressed with the number of companies across Canada that are focusing on the need to transition and really move towards net zero and that are putting themselves in a position to succeed in that environment.
I am going to go back to Mr. Hutchens, just to give you a bit of a head's up.
I want to respond a little bit to the conversation we just heard. I want to push back a little bit. I don't think anybody here expects us to be able to get this all done in one year. I think the reason that we can't go to net zero all at once is those cost burdens. I think that's what we've been saying for quite some time. This is a transition. This is why it's going to be a gradual transition over as many as 30 years.
I just think that the 2000% numbers that we've been hearing just now are a little disingenuous. The more fuels that come online and are adopted, the more will be produced and the cheaper it's going to become over time—this year, in two years, in 10 years. I wanted—
Just to clarify my earlier response and maybe tie a couple of those pieces together, when we were talking about the $2 and $20 numbers, that is for the commodity alone. I think I referenced the percentage of the bill that is. You have to look at the overall bill impact. You also have to look at how these costs can come down, and will come down over time. It's really trying to figure out what those costs look like.
Probably the most important point I could make today is the fact that we have no idea where or which process those costs are going to come down best and fastest. The thing we have to think about from a policy standpoint is not to throw out any options early on. You have to make sure that you have the infrastructure, so that if RNG or hydrogen becomes really cheap, if carbon capture and storage comes to light, if there are new technologies that come in on the electric or the gas side, we can shift and make sure that we're utilizing the best possible resource to have the climate impact that we're looking for and the cost impact that we're trying to avoid. It has to be that balance. If you throw away any of the options early on, then we won't be able to shift or use what's most beneficial for our customers.
To be clear, we are driven by what our customers and policy-makers want to do. At the end of the day, if that goal is for our customers to want to reduce their greenhouse gas impact and they want to buy and pay additional...which they do. With FortisBC they willingly buy renewable natural gas from us because of the lower environmental footprint it has. Our customers should be free to do that. If policy drives us in that direction then we must have all options on the table and know when to pull them off, but you can't pull them off too soon.
It is, again, about looking at that balance of options. It's finding the cheapest renewable natural gas sources we can. It's trying to get breakthroughs in technology on the hydrogen side of things.
Hydrogen is going to play a big role, but not necessarily within the current structure that we have. We're doing studies right now with the University of British Columbia in the Okanagan to figure out how much hydrogen we can put in our gas stream and still manage the burn rate, the customer effect and impact, that we need to and how that impacts our system.
At the end of the day, hydrogen doesn't transport in the same way that natural gas does. It's a less dense fuel and so it needs higher volumes. Also, it can cause operational issues, like hydrogen embrittlement within the existing pipe network that we currently have. We have to figure out solutions for that kind of stuff so that we can, again, figure out those paths. Is it hydrogen? Is it RMG? Is it carbon capture? Is it carbon capture at which end of the pipe? At the end of the day, you have to have the pipe, or you can't ever make that decision, and that's our main thesis: you have to have that pipe. You have to have the pipe, because it can transmit clean molecules just like electric transmission lines can transmit clean electrons.
As a point of clarity—
I listened carefully to what Ms. Trudeau, Mr. Boies and Mr. Verlez said. Something I took away from all three presentations was the importance of a regulatory framework.
I believe Mr. Boies talked about clear regulations for low-carbon energies. When the committee was studying the forest industry, we had a similar discussion. Something struck me as important, and it may just be one of many considerations. If the government were to include a low carbon footprint requirement in its public tenders, it might be a good way to stimulate the market.
I'd like Mr. Boies and Mr. Verlez to explain what they mean by a regulatory framework. After that, I may have a question for Ms. Trudeau.
I'm happy to attempt an initial response. Mr. Verlez can then take over.
Clearly, a regulatory framework encourages good behaviour. Let's take the example of a big oil company in the Netherlands or the United States investing in production assets like low-carbon biofuel. If they were to use the technology in our Varennes project, they would produce a carbon-negative fuel. These days, in fact, it costs less to produce that molecule than to not comply with the regulations. So as you can see, in creating what we unfortunately call a “stick”, we are encouraging the world's oil companies to invest in their production capacity, to increase their production, and therefore to behave properly until we get either to the level of compliance we want or to where we have to impose a cost on non-compliance.
Obviously, a framework like that provides an incentive to invest. Just compare the current price of methanol in the Netherlands to the price in Canada. In the Netherlands, it costs $1.37 Canadian per litre, while in Canada it costs 44¢ per litre. It's the same molecule with the same carbon intensity. The only reason for the gap is the regulatory environment, which forces a company like Shell, for example, to sell the molecule to the part of the world where it makes the most money and where the cost of non-compliance is the highest.
The unfortunate thing is that, because we have no regulations in Canada, even though we have production assets and we can produce low-carbon or carbon-negative ethanol—such as we were producing in Edmonton that was -20 carbon intensity in the British Columbia system—it's now more profitable to sell it in the U.S., in California, rather than in Canada. So California benefits from the reduced CO2 levels.
I would like to come back to that, Mr. Verlez, and perhaps Ms. Trudeau can also join in the conversation.
I have a concern. Last week, we spoke with a deputy minister about Canada's hydrogen strategy, which seems to be largely focused on something called grey hydrogen.
In a regulatory framework, do you think we should categorize the different types of hydrogen?
Earlier, Mr. Verlez spoke about Evolugen's project to produce hydrogen from hydroelectricity. For one ton of hydrogen, we know that grey hydrogen produces outputs of about 10 to 11 tons of CO2.
If the government wanted to adopt a hydrogen strategy, should the regulatory framework include measures that would calculate the carbon footprint of hydrogen?
Thank you to all the witnesses for being here today.
I'm going to start with Mr. Hutchens from Fortis, if only because I not only pay my gas bill to Fortis, but I also pay my electrical bill to Fortis. All that electricity is made in the west side of my riding. There's a company that's developing a renewable natural gas plant in my riding, and hopefully that gas will be put into Fortis pipes.
I have two questions. One is a clarification about your view of the world by 2050, the Fortis world. I didn't catch what percentage of your gas production would be net-zero carbon. I thought you said 50, and that confuses me, because I thought we'd be at zero by 2050.
That's my first question.
Mr. Cannings, that's a good question. It's not one or the other, it's both or all of the above. Hydrogen should be viewed as being used in different ways within the economy to clean up the greenhouse gas emissions.
It can be used, as you've mentioned, whether it's as direct end-source use for transportation fuel cells or whatever that might be, but you have to look at the economics of how much hydrogen costs to transport it to where you're using it. I know we talked a bit about the different colours of hydrogen. We need to make sure that we're looking at the carbon-free hydrogen, when we use it, say, in our natural gas stream, which is also a very important path to use, because we can't necessarily get to the point where we can use a 100% renewable natural gas. Therefore, hydrogen will play a role in there.
You're right. When you look at the studies, I have heard everything from 5% to 20%. That's why we are spending a lot of time doing that research so we know exactly what it means for our system. Then, of course, you have to see how it behaves with your system, because every system is different. There are longer systems; there are systems that have different physical characteristics with the types of pipe, and so on, and the compressor stations. All of that has to be worked out so that you can get the right percentage for your system. However, at the end of the day, if you look at that diagram of the different paths that hydrogen can take, we shouldn't eliminate any of those paths now. We should see which ones we can use.
Electrolyzers might not be cutting-edge technology. The cost will come down, because we'll start building more of them. That's manufacturing efficiencies and getting cost-effective movement down that cost curve, but what we really need are some breakthroughs in technology.
How can be break that hydrogen and oxygen bond apart cheaper than basically the brut force of electricity to break those bonds? What other ways are there of producing hydrogen that we could use?
My question will be for Mr. Hutchens.
I will just say off the bat that as a Fortis B.C. customer myself, one of the biggest complaints we get in our office is the high gas bill. Because you mentioned “affordable”, I thought it was fair to bring this up. Some of those delivery costs, not to mention added carbon tax, are making natural gas that we produce right outside our back door very unaffordable in terms of heating our homes in the winter. We do well, of course, up in our area, but there are many Canadians who are simply struggling just to pay their gas bill. I'll just leave it at that.
I think Conservatives care, and maybe this is something that Liberals should be more concerned about: how affordable all of this is and how affordable are some of these measures.
Seeing that we already have over 200 years of natural gas supply outside in the B.C. Peace region, we know it's semi-affordable the way it is. My concern, based on what Mr. Lloyd asked you before, is this dramatic increase to that already, as I said, affordable but very challenging gas bill that our constituents pay every month. Multiplying that or doubling that, or even increasing that in any way is very concerning to me.
What are your comments around that? How much is adding renewable, whether it be either hydrogen or renewable natural gas, into the system actually going to cost Canadians?
Again, those are great questions. They're ones that we talk about quite often at our gas company in B.C.
We do have studies on the cost differential. Obviously, I don't have them at my fingertips, but we can provide that. That has to be part of the conversation from the committee's standpoint to understand this, because what we do is we respond to policy. If the policy says the curve has to look like that, we try to find the most cost-effective way to meet the needs of that curve.
On your other point—I can't miss this opportunity—one of the most important things we can do is to offset greenhouse gases outside of Canada, outside of B.C., using B.C. natural resources, like methane right out of the ground, turning it into LNG and sending it to Asia. We are big proponents of that. We have big projects that are based on that principle. At the end of the day, this is a global market. Look at the abatement cost curve and start from the left, the cheapest stuff to do first. It might not be spending money in a province or a state or a country that you want, but we have to remember that this is all part of a global climate policy discussion. We should all be looking at knocking off the cheapest ways of getting the climate impact we're looking for.
Thank you to all the witnesses today. This is a fantastic and really interesting discussion that we're having together.
I know you've been on the hot seat there, Mr. Hutchens, so maybe I'll just talk about the Wataynikaneyap project. Thank you for mentioning that. I know it's a game-changer for indigenous communities up in the northwest. I want to give you a shout-out on that, because you mentioned it in your opening remarks.
Mr. Boies, Mr. Simard asked you a question earlier about the regulatory framework. I'm trying to get better understanding of that.
You say that, because of the regulatory framework, it's more profitable to send renewable natural gas or hydrogen produced here to California or the Netherlands. Could you elaborate on that?
We want to invest and produce these renewables at home and here we are selling them elsewhere since the market is better. That's really intriguing, but I find it's rather astonishing.
Can you explain it in a little more detail?
Thank you for the question and I can certainly answer it.
It depends on the price you put on CO2 emissions. Life cycle analysis is used worldwide to determine the carbon intensity of each fuel.
For example, I was saying that our project in Varennes would produce carbon-negative biofuels. If California, for example, imposes a cost of $200 U.S. per ton of CO2 emitted, and in Canada we have no regulatory framework that puts a price on CO2 emissions, I'm going to sell that fuel in the market that pays the most for every decrease in units of carbon intensity.
This is all comparable to what happens with gasoline. Let me give you an example. Gasoline has a carbon intensity of about 98, depending on the market. The fuel we're going to produce in Varennes has a carbon intensity of -10. So the difference is 108, at $200 per ton of CO2 emitted. That is a profit for the seller of that molecule.
Right now, because there is no incentive to invest, when my partners—Shell, Proman, Suncor and the Quebec government—invest in an asset in Quebec and they sell that low-carbon molecule in Quebec, they get a negative return on their investment and they lose money. So they are going to export it to Europe, the Netherlands, California or British Columbia, for example.
Actually, we've been working on it for 10 years. About twenty projects are in development or under construction. We have one that is operational, but it's not yet producing enough to meet the demand.
At the moment, we're required under Quebec legislation to deliver 1% RNG. In a year, it will be 2%, and by 2030, it will be 5%, and we will meet those targets. When you start a brand new project, you need approvals and construction time to get to the point where demand and supply intersect. We believe this will not be an issue. The supply is growing. It just takes time. It's the same with hydrogen. If you want to have that operational by 2030 or 2040, you need to start now.
I don't want to take up any more of your time, Mr. Simard, but if the Chair will allow me, I would like to say something about the price.
May I, Mr. Chair?
Decarbonization comes at a cost, unless we're talking about energy efficiency. The important thing is to do it at a lower cost. Along the lines of what Mr. Hutchens was saying, here in Quebec, for example, for a fairly large elementary school or business, renewable natural gas costs almost twice as much as natural gas. Instead of $30,000, for example, it costs $58,000. However, electricity would cost $10,000 more than RNG. It remains the most expensive renewable energy source that requires no additional investment.
If we help our customers reduce their energy consumption—
I forgot to mention, when I was talking to Mr. Hutchens in the previous round and in partial answer to what Mr. Zimmer was asking, that I get renewable natural gas on my Fortis bill. It costs me about three times as much when you take into account the fact that I'm not paying any carbon pricing on that, etc. That's certainly the consumer thing. That's a big difference. I'm hoping that can come down.
I'll stay with Mr. Hutchens. Mr. Hutchens, you were talking about the costs of transporting hydrogen and things and all of these extra costs when we're developing new technologies and new transportation systems. Isn't that something where the governments, whether they be federal or provincial, should get involved, so that it's not left up to the energy producers to shoulder and try to compete unfairly against old technologies?
Something like a hydrogen transportation infrastructure.... I'm not a hydrogen technologist, so I don't know what that would look like. Isn't that something where the government itself could step in to say that it's going to do this?
Just like the government builds the highways and provides money for the electrical grids between provinces and across the borders, etc., isn't that something where the federal government could really make a difference?
Thank you to all the witnesses here. We've heard some great input so far of what we need to consider in this. I really appreciate all the information we're being given.
I'm going to point my questions to Ms. Hansen. First of all, Ms. Hansen, congratulations on your company's announcement earlier this week on your renewable natural gas partnership in Ontario. I think that's great news for the industry.
As much as some of my colleagues have drilled into the actual dollar cost of what we're talking about here, I'd like us to talk about the CO2 cost of what we're expanding and the nature of how much CO2, or power, if you will, is required to produce renewable natural gas vis-à-vis other natural gas.
I'm looking for the power input to a power output ratio, if you can, please.
For renewable natural gas, I would say that it really depends on what the source is. If you have an active landfill where you are capturing that, there may not be a significant incremental power input if you're just capturing that. Some of what we're doing with RNG is just capturing emissions that would otherwise vent to the atmosphere, so there is some increased electrical input to clean it up, to scrub it and have that in. I can provide you with that. That's part of the incremental cost that goes into the production of RNG.
On the hydrogen side, again, it really depends on what that source of hydrogen is. For some of the advancements that are being made today, when you pair the hydrogen up with renewable sources like wind and solar and it's used as an energy source, it depends on what the pricing mechanism is within that existing franchise. If this is power that would otherwise be curtailed, you would have a very low cost for that power, and those would be the opportunities that we should be pursuing first, where you have that opportunity to capture that.
The right answer is that it varies quite a bit, and this is why we have to do a number of studies and look at where we can most optimize the infrastructure that we already have. As has been pointed out a number of times today in the comments, we have this incredible gas infrastructure in Canada that we should be looking to utilize, and—
With respect to the regulatory framework, it would be helpful to have mechanisms that allow us to carry out pilot projects, because they need to be done, especially in the United States. Generally, it's not easy to do them.
As Ms. Hansen said, we will be testing sections of networks that are not all made of the same material. For example, we need to be careful about the hydrogen mix used for industrial customers, because they have more sensitive devices. In 2022, we will conduct two closed-loop pilot projects to test our residential and commercial gas lines, so we can determine the maximum amount of hydrogen they can hold. We'll also conduct an industrial project at a central heating plant in downtown Montreal, where we will inject hydrogen into a boiler. We will proceed by trial and error and studies will be done. We may get federal support for research and development.
Other than injecting hydrogen, we could use sections of pipe from a natural gas network. We would considered it as an energy network, and completely dedicate those sections to hydrogen. That's a second possibility. There's also electricity-to-gas conversion, which involves converting CO2 extracted from an industrial site into renewable natural gas. They become completely interchangeable and there's no limit, meaning we can use 100% of it.
So we have several avenues to explore in terms of hydrogen in gas systems. There are billions of new and well maintained underground systems in Canada. We need to look at natural gas systems as energy systems and determine how we will move them towards decarbonization.
This is a fascinating discussion today, and I'm looking forward to getting involved.
The first question I have is for Mr. Hutchens.
I want to pick up on something that my colleague from the NDP was touching on earlier, and that's the use of renewable fuels and particularly hydrogen through the existing networks for home heating.
If we're going to have to potentially build out more infrastructure to transport clean fuels for this purpose, I'm curious why we would invest in blending in some of these other activities when there may be other options out there, such as looking to increasingly electrify heating and stoves through our existing electrical grid.
Mr. Weiler, it just comes down to the cost impact and whether or not you're looking at using and utilizing existing infrastructure that we currently have that can move clean molecules versus building new additional infrastructure. That's the difference.
I think Mr. Patzer brought up the impact assessment in terms of building the new pipes. That's what makes our existing system so valuable and important right now; it's to utilize that infrastructure. Whether it's the existing pipes or the right-of-ways, it's really making sure that we're not ignoring the extreme value, the huge value, that our existing infrastructure has and the value that investors put in the ground and our customers have paid for. To build something new without figuring out how much you can use of the existing infrastructure would be a little bit short-sighted, I think.
Now, whether or not we look 50 years out and we see something that might change in year 10, 20, 30 or 40, then yes, we can shift, but we don't know enough now to shift away and say that we shouldn't be investing and continuing to make sure that these systems are resilient.
If I had more time, I'd tell you all about Texas. It's a great lesson learned about how not to do it.
To be polite, that's an understatement.
British Columbia is leading the way with its low-carbon fuel standard modelled after California and Oregon, among others. It's a great start. It's the most forward-thinking market in the country right now.
As for our goals, if we compare them to the ambitious goals of some U.S. states, some European countries or even the European Union, we are years behind.
So it will be hard to catch up. Earlier, Ms. Trudeau, I believe, mentioned that we can't decide to build our capacity when we wake up one morning. These projects are developed over three, four or five years and require hundreds of millions of dollars.
So if we want to get there by 2030, 2040 or 2050, we can't wait until then to start thinking about it.
I'm going to continue on with Monsieur Boies. I'll pick up on something you brought up in your exchange with Mr. Patzer, I believe. You brought up an example about being able to use green energy from green sources when you were doing your projects. You used a Suncor windmill example.
I have a small but very innovative and very old power plant in my riding. It's Silversmith Power in Sandon, B.C. I believe it's actually the oldest operating hydroelectric system in the world. It's totally green. It's feeds off five creeks, so it's run off the river. There are no dams involved, but it produces the same amount of electricity all year round.
Calgary Transit wanted to use this power to run their electric transit system, but they were unable to sell those green molecules. They wanted to sell their green electrons to Calgary, but were unable to and certainly were unable to get the value for them because they had to sell it into the BC Hydro grid.
I'm wondering how we can fix that. Is this a federal responsibility? Is it a provincial one? Is it a mix? Where is the regulatory change we need to make, so that projects like that can get a fair price for their green electrons?
I'm going to jump back into a topic that's been brought up by Mr. Boies, but I'd also like to ask Madame Trudeau the same question.
Mr. Boies, you mentioned that we need to develop the market for these clean fuels locally. You mentioned some examples in California and the Netherlands, where there are attractive markets for low-carbon fuels. I think you also mentioned B.C., with the LCFS as something that really helps create that market.
At the federal level we do have the clean fuel standard, which, of course, requires refiners to produce fuels, increasingly, with lower carbon intensity. With this in mind, I'm wondering what you see as needed over and on top of this to create this type of market across Canada.
As Mr. Boies said, we need to use both the carrot and the stick, that is to say the regulations that impose minimums and provide predictability. In Quebec, we're talking about 5% by 2025, but we haven't yet passed the regulations for the 10% by 2030 target. We should be talking about 20%, 25% and 30%, which would create an obligation. The binding aspect is really important.
The clean fuel standard will add a lot of value to renewable natural gas. Our refiners are already asking a lot of questions about it.
Various other sectors also need help. I'm thinking of cement plants that still use coal and are competing with other cement plants that also use coal, but are under a different government jurisdiction. If we want to force our cement plants to become cleaner, but they can't move towards electrification, perhaps we should help them initially pay the price difference between coal and natural gas, and then gradually decrease the subsidy.
The price difference between coal and natural gas is very significant, and some customers would initially need a little help with operating expenses to make the transition.
If I may, I would like to talk about something we haven't talked about today, namely the economic benefits. We have talked about the costs of RNG, but one study shows that potential construction projects in Quebec would create 88,000 jobs, 15,000 of which would be in production. So we haven't talked about the major economic benefits of these circular economy projects.
I can forward the study to the committee at a later time.
Because of where our existing infrastructure is located in Ontario, we have our compressed natural gas refuelling stations along the Highway 401 corridor. Then we have our current power-to-gas green hydrogen facility located in Markham, Ontario.
We're looking at how we can tie into that existing infrastructure. The CNG stations can be converted to hydrogen and we can use them as hydrogen fuelling stations. We also have an opportunity with our existing infrastructure in Ontario and Quebec to look at how we can serve and create that dynamic.
We service, obviously, the Sarnia industrial area as well. Because of our existing infrastructure, particularly in Ontario and Quebec, we can work with some strategic players to really develop that market.
We also have a similar opportunity in Alberta with our existing infrastructure there, and into B.C., along with Fortis, how we serve with our gas pipeline infrastructure.
On that note, thank you very much, witnesses. We very much appreciated your time here and the very valuable information you passed along today—and some more information that may be submitting in the future, as Mr. Zimmer just reminded us.
Just as a reminder, committee members, on Monday we will continue our in camera session to finalize the previous report. Next Friday we will return to this study.
On the first point, if there are any further proposals that we're going to be talking about on Monday, it would be great if they could be passed along in advance.
On that note, the meeting is adjourned.