Natural Resources Committee on Nov. 29th, 2012

[Brent Lakeman]

Sure, okay.

In conclusion, it must be remembered that while CCS is viewed by the research community as a key approach for reducing global greenhouse gas emissions, it should not be regarded as a silver bullet for all sectors or all jurisdictions. CCS needs to be viewed as part of a larger set of greenhouse gas management tools. Without having CCS in the tool box, the cost of the other tools becomes significantly higher. Lowering overall carbon management costs and increasing overall system effectiveness ultimately require an approach whereby biomass and other renewable energy sources, coupled with innovative energy storage technologies, are integrated with CCS systems.

In conclusion, we have seen great progress in advancing CCS technologies over the past 20 years. While progress has slowed since 2008, Canada remains a leader, with three to five major demonstration projects planned over the coming years. It is important to continue and enhance our leadership role to realize further economic benefits as we help other nations advance the technology and as we continue to drive down costs and ultimately identify more opportunities for CO₂ utilization.

Thank you very much.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Lakeman and Ms. Barry, from Alberta Innovates Technology Futures.

We will go now by video conference to Paris, France, to the International Energy Agency and Keisuke Sadamori, director, directorate of energy markets and security; Adam Brown, energy analyst, renewable energy division; and Anne-Sophie Corbeau, gas analyst.

If you would, go ahead, please, with your presentation of up to 10 minutes, and again thank you very much for being here with us today and giving us the information that you have.

[Keisuke Sadamori, Director, Directorate of Energy Markets and Security, International Energy Agency]

Thank you, Chairman, for giving us the opportunity to talk about natural gas, oil, energy efficiency, carbon capture and storage, and renewables.

First let me focus on the natural gas. Canada has been exporting natural gas to its southern neighbour for decades, and until the end of the last decade, nobody expected that trend to change. On the contrary, U.S. gas production was seen by many as stagnating and ultimately declining. Mexico was slowly turning into an LNG importer.

Then the shale gas output in the United States was multiplied by a factor of 10 between 2005 and 2011, and this changed everything. Canada’s gas exports to the United States declined abruptly, leading to a 30-bcm drop in production from 2005 to 2011, to 160 bcm. More important, since 2011 the United States has been pushing more gas towards its two neighbours because of the oversupply in its own market.

Mexico is importing less LNG and more Henry Hub indexed gas from the United States. The worst may still be coming as Marcellus, the prolific shale player in the northeast of the United States, is just at the beginning of its development.

But Canada has gas, conventional and unconventional. Tight gas has been produced for a long time, while shale gas is still in its infancy. The only problem is that this gas, once the transport costs to bring it to the United States are added, may no longer be competitive enough against U.S. natural gas production.

Additionally, there are concerns regarding the environmental impacts of developing shale gas, but shale gas can be produced in a way that respects the environment, as our recent report, “Golden Rules for a Golden Age of Gas”, demonstrated.

In order to stabilize gas production and revenues from gas exports, Canada should look at other markets. There is only one solution—LNG exports. Japanese, Korean, and Chinese companies have been acquiring assets on the west coast of Canada to bring the gas back home. Two of these projects have been given authorization to export.

These projects have one crucial advantage: they are better located than the U.S. projects, most of which are located in the Gulf of Mexico. Many U.S. LNG projects are based on existing LNG import facilities, so the investment costs will be lower. The U.S. greenfield projects, however, will not benefit from this advantage. Similarly, most new planned LNG projects in the world in Australia, Papua New Guinea, Africa, and Russia will be greenfield projects, and their development costs will depend on the specificities of the LNG projects.

Finally, there is the question of the price at which this gas will be exported, or rather of the indexation, oil or spot. The only LNG project recently sanctioned in North America, Sabine Pass, will be based on Henry Hub indexation, but it is sourcing its supply on the wider U.S. gas market, while the Canadian LNG projects will depend on the more dedicated—and still to be developed—sources of gas supply in western Canada.

International oil companies involved in these LNG export projects may prefer the traditional oil indexation, similar to what has taken place in Australia, but if Asian buyers are involved in the project, they may push towards spot indexation, either Henry Hub or its Canadian brother, AECO. Unlike in North America and Europe, there is no spot price in Asia. The IEA has been recently working on a report looking at how a spot market could be developed in Asia. This report will be issued in early 2013.

Second, there is oil. Canada is also an oil-rich country. Let us now have a look at the development of oil resources, notably oil sands.

In the medium term, the production of oil sands is expected to increase by 1.1 million barrels per day to 4.6 million barrels per day by 2017. Increasing volumes of Canadian bitumen production will still find their way to U.S. markets as heavy oil refining capacity is added, but Canadian producers will have to seek new markets and new transport solutions.

Looking forward, there are clearly political and local constraints to expanding, reversing, and/or building new pipelines. It is clear that Canada, along with the provinces, is looking for new options, but in the meantime output is rising quickly. Tight pipeline capacity is one of the major reasons that Canadian crudes are priced at a discount to WTI, but the spike in the discounts has hurt Canadian producers’ bottom line this year, and companies are now openly questioning to what extent they will remain a fixture in the market in 2013 and the medium term.

Canadian oil sands are set to play a key role in the medium term by raising the non-OPEC supplies by an additional 1.1 million barrels per day. That's the second-largest source of growth among the non-OPEC countries besides the United States, but Canada's projects will compete for financing, labour, and takeaway capacity with the rising output of tight light oil in the United States. As a result, these constraints and market dynamics are expected to delay around 200,000 to 300,000 barrels per day of Canadian oil sands output to beyond the 2017 timeframe.

Canada should be commended for its proactive approach to improving the social licence to produce from world-class oil sands resources. Now the challenge moves outside Alberta. The solutions of minimizing environmental and social impacts are based on technological and process innovation, and I want to recognize and commend the efforts industry is making in these areas, especially through such collaborative efforts as COSIA, but I urge industry to redouble those efforts and I remind you that the onus is on producers.

My point with regard to responsible unconventional oil and gas production is simple. This is not just good PR, it is good business. It is in all our interests that these industries remain healthy and welcome to operate.

Third, let me turn to energy efficiency. The release of the World Energy Outlook this month highlights the vast scale of what we call “the hidden fuel”, the energy efficiency. Despite the vast scale and high economic returns, it's not always easy to engage all the different consumers and decision-makers in the imperative to improve energy efficiency.

Canada has higher energy intensity, adjusted for PPP, than any IEA member country. This is largely due to its concentration of output in energy-intensive sectors: cold climate, large distances, and high standard of living. Final energy consumption has grown continuously over the past decade, though at a lower rate than the economy as a whole.

Canada's energy intensity, adjusted for PPP, has declined on average by 1.4% between 1990 and 2009 due mainly to the energy efficiency improvements, and this improvement in energy efficiency, led by the Office of Energy Efficiency at Natural Resources Canada, is the progress IEA is delighted to see.

Canada has strengthened energy efficiency policies across all sectors—industry, buildings, transport, and utilities—in the past two years. In July 2011 Canada’s energy ministers agreed to a collaborative approach to energy with a companion action plan. Specific areas covered by the plan include a more stringent model energy code for buildings, a next-generation energy rating system for homes, project financing tools, transportation, product regulation, and industrial energy management standards.

Fourth, let me turn to carbon capture and storage, CCS.

Canada has been actively supporting and developing carbon capture and storage technologies, both on a federal and a provincial level. The provinces of Alberta and Saskatchewan especially have been at the forefront of development. Saskatchewan is host to one of the best-known CCS projects in the world in Weyburn, successfully combining the long-term storage of CO₂ and enhanced oil recovery with CO₂. The main power utility in the province, SaskPower, also has a large power sector CCS project under construction. Furthermore, with significant financial support from the Province of Alberta, Shell has recently announced its investment decision on a new CCS project called Quest, linked with oil sands development at a large upgrader facility. Alberta has also put a lot of effort into developing a comprehensive legal framework to cover various aspects of storing CO₂. The IEA welcomes Canada’s leading efforts in the field of CCS.

Fifth is renewable energy.

Renewable energy is playing a large and growing role in Canada's energy mix. Canada's power system already relies to a great extent on hydro power and accounted for almost 59% of total generation in 2011. This large hydro power potential should be further developed over the medium term. Known hydro power renewable developments are expected to take place mostly in solar PV and onshore winds, with Ontario and Quebec providing the largest growth. In 2011, cumulative installed capacity in Canada stood at 560 megawatts for solar PV and 5.3 gigawatts for onshore winds, mostly located in these two provinces. From 2011 to 2017, growth in these two technologies is expected at 3 gigawatts and 9 gigawatts respectively.

The IEA's 2009 in-depth review recommended that Canada develop a long-term policy that integrates renewable energy into the overall national energy strategy while taking into account the geographic, geological, and resource differences between the provinces and territories. It stressed the need to remove and overcome non-economic barriers as a first priority to improve policy and market functioning while having regard to Canada's unique national circumstances. The IDR called on Canada to commit to long-term, effective, and predictable support mechanisms in order to provide developers and investors with a stable regulatory framework. It also urged the government to develop more ambitious programs to facilitate the use of renewable electricity generation, microgeneration, and heating in geographically isolated regions in order to offer an alternative to the consumption of petroleum products. Many of these messages are still relevant today and for the outlook over the medium term.

Thank you very much.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Sadamori, for your presentation.

Again from the International Energy Agency, we go to our final presenter today so we can get to questions and comments from members of the committee.

From Gradek Energy Incorporated, we have Thomas Gradek, president. Welcome, sir, to our committee.

Go ahead with your presentation. You have up to 10 minutes.

[Thomas Gradek, President, Gradek Energy Inc.]

Thank you, Mr. Chair, Hon. Mr. McKay, and distinguished members of Parliament.

I thank you for inviting me to make a presentation on Gradek Energy Inc.'s technology.

Imagine if we had the technology to clean up tailings ponds. Imagine if Canada could extract oil sands without creating a tailings pond. What if we had a new technology?

Gradek Energy Inc. is an innovative cleantech company that has designed an energy-efficient, reusable, environmentally responsible, hydrocarbon separation technology that can be used to assist the Canadian oil sands industry achieve its ultimate goal, which is sustainable production growth, together with reclamation and restoration of operating sites in a timely and cost-efficient manner.

Gradek Energy Inc.'s pilot plant has proven that its proprietary RHS process is capable of treating tailings by separating hydrocarbons from solids while recovering valuable bitumen and recycling warm process water.

According to an independent study conducted in July 2010, the Oil Sands Research and Information Network estimated that in 2008, about 750 million cubic metres of tailings existed within Alberta's tailings ponds. The study predicts that if there is no change in tailings management, the inventory of fluid tailings is forecast to reach one billion cubic metres in 2014 and two billion cubic metres in 2034. The growth in tailings volumes attest that current technologies have not been successful in meeting the criteria and objectives as outlined by directive 074 of the Energy Resources Conservation Board and by the Canadian Environmental Assessment Agency.

The criteria and objectives can be summarized as follows: to minimize and eventually eliminate long-term storage of fluid tailings in the reclamation landscape; to maximize intermediate process water, recycling it to increase energy efficiency and to reduce freshwater import; to minimize loss of valuable resource associated with tailings ponds; to create a trafficable landscape at the earliest opportunity to facilitate progressive reclamation; to eliminate or reduce containment of fluid tailings in an external tailings disposal area during operations; to reduce stored process-affected waste water volumes on site; and to ensure that the liability for tailings is managed through reclamation of tailings ponds.

The Pembina Institute and the Water Matters Society of Alberta conducted a review of the submitted tailings plans. They found that only two of the nine mine projects would meet the requirements for the regulations to reduce toxic tailings starting in 2011. The proposals for the other seven projects would not meet the targets for reducing tailings by 2011. Furthermore, a number of project proposals indicated that they would not meet reductions until 2023, and would not meet rules for developing solid surfaces for over 40 years.

This reality will have a direct negative impact on the perception of sustainable energy development in the Canadian oil sands. Gradek Energy Inc. can mitigate this by deployment of its technology to help Canadian oil sands operators meet criteria and objectives as outlined by directive 074, the Energy Resources Conservation Board, and the Canadian Environmental Assessment Agency.

The reusable hydrocarbon sorbent technology is an organic bipolymer bead that allows instantaneous hydrocarbon recovery upon direct physical contact without the need for any catalyst or chemical reaction. I have brought with me some samples in order to show you the process. The attraction of hydrocarbons to the RHS beads is strictly a physical attraction, causing no alteration to the absorbed hydrocarbons, thereby providing the perfect transport medium to extract hydrocarbons from any stream with minimal energy requirements.

In June 2010 Gradek Energy Inc. commissioned, in collaboration with a major Canadian oil sands operator, a three-and-a-half tonne per hour pilot plant to test the proprietary bitumen recovery process using RHS bipolymer beads. The pilot plant is located in the heart of the Montreal East petrochemical refinery district. The pilot plant benefits from access to qualified petrochemical expertise and a full-scale bitumen laboratory, including monitored security and established best safety practices. The facility currently employs seven full-time specialized workers and carries out research and development for advanced testing and process improvement.

The pilot plant is currently processing over 300 cubic metres of Alberta oil sands tailings. Based on pilot plant test results to date, Gradek Energy Inc.'s bitumen recovery process has achieved the following results: greater than 98% bitumen and total petroleum hydrocarbon recovery; 95% naphthenic acid reduction; over 60% of process-affected water is recyclable, and at a high temperature; high confidence of the economic viability of the business model; and feasible scale-up designs and performance.

On conclusion of the pilot test protocol, Gradek Energy Inc. will build a 500-ton-per-hour commercial prototype of the RHS bitumen recovery process in Alberta. Gradek Energy Inc. has attracted international recognition, and, in pursuit of a bold vision, has formed a strategic collaboration with Veolia Water Solutions and Technologies North America and BASF Global, which are keen to contribute their extensive expertise in engineering, testing and design, project management, and construction and operating experience to ensure operational success of the commercial prototype.

BASF is the world’s leading chemical company, employing over 111,000 employees in 370 production sites worldwide and serving customers and partners in almost all countries of the world. Veolia is a wholly owned subsidiary of Veolia Environnement, a publicly listed company on the New York and Paris stock exchanges with a $5 billion capital market, operating in 69 countries with 96,650 employees.

In summary, Gradek strives to become the partner of choice to the Canadian oil sands industry for the provision of tailings management services. The near-term objective is to offer a sustainable solution for tailings management that will favourably position the Canadian oil sands on the international scene. Gradek’s hydrocarbon recovery process translates into significant value added by allowing Canadian oil sands operators to increase bitumen production in an environmentally sustainable manner by transforming tailing stream waste into a clean and alternative energy source.

The main challenges and barriers to innovation, development, and deployment of Gradek technology have been determined to be access to necessary financial and human resources to bridge technology from development stage to commercial deployment, collaboration and alignment between industry operators and technology providers, and timely access to tailing ponds. As well, the Canadian renewable and conservation expenses program has not evolved to consider the growing importance and visibility of the Canadian oil sands industry and does not encourage innovation regarding waste heat recovery, water conservation, and resource maximization.

The role of the federal government to foster innovation and deployment would be to adapt the CRCE to incorporate investments in innovation regarding Canadian oil sands tailings reclamation; to formulate policy and metrics to recognize the transformation of extracted bitumen from Canadian oil sands waste tailings into a clean alternative energy source; to play a proactive role in promoting the adoption of innovation to achieve internationally recognized low carbon fuel standards; to level the playing field for the competitive benefit of the Canadian oil sands industry by permitting the expansion of production in an environmentally sustainable manner without increasing the carbon footprint, using Gradek’s technology; and to facilitate the collaboration from a Canadian oil sands operator by providing incentives to implement the commercial prototype on a small-scale settling pond and conduct temporary and/or permanent reclamation testing.

Thank you very much.

[The Chair, Conservative, Leon Benoit]

Thank you very much, Mr. Gradek, from Gradek Energy Inc.

We're ready now to go to questions and comments.

Mr. Allen, you have up to seven minutes.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

Thank you very much, Mr. Chair.

Thank you to our witnesses for being here today.

It's very interesting. I think there are maybe some pretty good lead-ins between our International Energy Agency comments and some of the comments that we have heard from our witnesses with respect to some of the good work that is being done on reducing energy intensity and some other things.

My first question is to Mr. Sadamori.

Your chief economist has made a couple of statements with respect to global demand for crude growing so quickly that the world needs every single drop of Canadian oil and, in addition, talked about the really small significance in terms of the impact on the CO₂ in comparing Canada to other major emitting countries. This is just peanuts. It's a small fraction of peanuts, actually.

With the demand growing for natural gas and the development growing for natural gas, both in the U.S. and through exploration in China and other places, including in Canada, do you still see that huge growing oil demand for Canadian oil in the foreseeable future?

[The Chair, Conservative, Leon Benoit]

Mr. Sadamori, go ahead, please.

[Keisuke Sadamori]

Thank you very much for your question.

Last month we released the Medium-Term Oil Market Report, and in the report we have estimated the oil demand and supply structure in the coming six years, from 2011 to 2017. In this, we expect that we'll see substantial growth of oil demand. By the way, that is mostly coming from the non-OECD countries, the growth in demand in China, India, and also in the Middle East.

We expect that we'll see the continuation of substantial growth, but at the same time, we are seeing somewhat slower growth compared with the forecast that we made last year. That is due to slower growth. Immediately before we released the Medium-Term Oil Market Report, IMF revised downward the global economic growth forecast. That is the fundamental picture of the growth.

On the other hand, in terms of the supply, we'll see somewhat comfortable growth in supply all over the world. First, about half of the world supply capacity of growth will be coming from North America. The biggest factor is obviously the light type oil from the United States, but at the same time we expect a substantial contribution by the Canadian oil sands. Also, we expect supply growth will be coming from the deepwater resources in Brazil as well.

That is the non-OPEC supply capacity. On the other hand, we have the OPEC growth as well. That is mostly led by Iraq. That is something that we looked at in detail in the World Energy Outlook that we released very recently for this year.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

Thank you very much.

[Keisuke Sadamori]

Yes, so that's the— [Inaudible—Editor]

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

Thank you. That leads me to a question. One of the other statements made was that it's good PR and good business to be able to do this in the most environmentally sustainable way.

Mr. Nelson, when you were talking about your technology, you said you'd been working on this for, I think you said, the last seven years, predominantly working your technology to get it more value-added in the supply chain in terms of just dumping the stuff in tailings ponds as opposed to getting other products out of it. You've done the demonstration projects, but you're slow to get adoption.

It seems to me there's a tremendous business case in this, with the billions of dollars that could be added with the zircon and the extra bitumen that we're getting out of the oil sands. Is it just a matter of lack of resources? The business case seems to be there. What are the other major stumbling blocks to the adoption of these technologies?

[The Chair, Conservative, Leon Benoit]

Mr. Nelson, go ahead, please.

[Scott Nelson]

Thank you.

We feel the technology is ready to commercialize. The industry is very much aware of it. They have participated in its demonstration. They have all the results. They haven't said no. They're just moving very slowly, coping with all the other issues that you've heard here, such as thickening tailings and uncertainty about their businesses.

It is new technology. There is always concern about risks, but we wouldn't have a lot of the modern things we have today if people didn't take the risk. I think the barrier is simply quite a conservative industry and something that's new, but we've literally done everything we can to ensure that the risks are minimized and the advantages are there.

Nobody likes to go first with new things. We need someone to do that. I think the COSIA organization was designed to share the risks. That would be one avenue. The other one is governments. It's clear that when new things happen, government often has to participate in the first implementation of those things; otherwise, these things drag on and on, and that's the unfortunate part.

We think it's urgent. We've done this a long time. We've spent a lot of money, and it's time to move ahead.

[Mike Allen, Conservative, Tobique—Mactaquac, NB]

One of the things is we've been captive to the U.S. market a little bit in that perspective, and because of that I think the discount on our oil right now is about $30 a barrel.

Do you see additional markets and being able to go to other markets as the impetus for that because of the additional revenue? At the same time, because of additional development in the resource, it's going to be even more important to do technologies like yours to make sure that we're doing it in a sustainable fashion and getting every value out of this.

[Scott Nelson]

The short answer is yes. It improves the social licence to operate. It shows that we're getting every drop of oil and every bit of value that we can out of the resource before we produce more of it, and that we're reducing the environmental impact. Some of the barriers to our oil in both U.S. and international markets relate to its reputation in the industry, so it improves that. It makes the projects more economical even if we don't expand, and it shows that we're extracting more from what we have, which is responsible and sustainable development.

Finally, this minerals industry can be the first export industry from the oil sands to China. We don't need a pipeline. It goes into containers and onto ships. It's a nice clean resource going off to China. It paves the way for this relationship that I think is important to all Canadians, and that's new exports.

[The Chair, Conservative, Leon Benoit]

Thank you very much, and thank you, Mr. Allen.

We go now to Mr. Julian for up to seven minutes. Go ahead, please.

[Peter Julian, NDP, Burnaby—New Westminster, BC]

Thanks to all our witnesses. What you told us today is very interesting.

I have a quick question for Mr. Gradek to start off.

You mentioned a survey of nine sites in the oil sands, seven of which were not meeting targets around tailings management. Is it possible for you to table that survey with the committee?

[Thomas Gradek]

I will be able to obtain that information from the review on water matters outside of Alberta that was submitted by the Pembina Institute. This was conducted in 2009. That is public information that is available.

[Peter Julian, NDP, Burnaby—New Westminster, BC]

Okay, thank you for clarifying that. It's much appreciated.

I'd like to come back both to you and to Mr. Nelson, because what you're speaking about is very intriguing. I'm very interested in the costs, and I've been up to the oil sands more times than I can count this year. I've been up with our national leader, Tom Mulcair, with the NDP members of this committee, and a couple of times on my own, all the way from Fort McMurray right up to Fort Chipewyan. One of the things I've been asking every time I've toured an oil sands site is the cost of reclamation.

To date, even though I've asked CAPP and I've asked the companies, we have not had any estimate of reclamation costs for any part of the pilot projects that are currently under way. Of course, that's extremely important for public policy. We need to understand what the costs are for reclamation in order to understand how public policy can best be oriented toward that reclamation.

Mr. Nelson, you were talking about moving to implementation from the pilot project that you've said has been successful. I'm wondering if you can give us an idea of the cost of implementation at one oil sands plant.

Mr. Gradek, you've mentioned having incentives in place to put in place a pilot project. Could you give us some sense of what the overall cost of that might be, and then in both cases, what you're looking for in terms of support from the federal government for these initiatives?

[The Chair, Conservative, Leon Benoit]

Mr. Nelson, could you start, please?

[Scott Nelson]

Yes, thank you very much. It's a very good question.

At any large mature site like Syncrude or Suncor, the facilities we would need to put in place, given the volumes of tailings we would handle, cost in the range of $400 million, which you then divide. This sounds like a big number, but bear in mind these oil sands sites have cost tens of billions of dollars to build. When you look at the amount of oil we could recover, which is 6,000 to 7,000 barrels a day for a very long period of time, the capital cost is about $30,000 per flowing barrel to recapture this oil that's going into the tailings ponds. That's versus the costs of building a new mining site and getting that amount of bitumen: $80,000 to $100,000 per flowing barrel.

The point is that if you can recover something from a waste stream efficiently, then it's going to be very attractive in economics, so we're proposing that this be done. The operating costs per barrel are around $10 for that barrel of bitumen that we're going to capture before it goes into the tailings ponds, and that's versus about $23 a barrel for bitumen that's mined and then put into an upgrader. Those are quite common numbers you would find in the public domain. It's about one-third of the cost of getting another barrel on a new project.

We're saying this is the low-hanging fruit, as I mentioned, and throughout the world you will find mining projects that are now going back in with better technologies, attacking their tailings and their dumps because of the higher prices of commodities, and reworking them. We believe that should be done here.

[The Chair, Conservative, Leon Benoit]

Mr. Gradek, go ahead.

[Thomas Gradek]

We have a proposed business model whereby we offer a service, and the service is free for the oil sands operator. They provide us their tailings, and we would be cleaning up their tailings, extracting bitumen that they would buy back and providing them with clean water that is warm because it's end-of-pipe. The tailings that come out from the plant are very warm, and there is a lot of dissipated heat that ends up in the tailing ponds, which is estimated at about $1.47 per barrel of bitumen in production.

Industry has also evaluated the cost for reclamation that they intend to put aside under a qualifying environmental trust at $1.33 per barrel of bitumen produced, so in terms of the cost that they have to bear and put aside or that they're losing because of their inefficiency, it's quite substantial.

[Peter Julian, NDP, Burnaby—New Westminster, BC]

Sorry, I'll just come back to the issue, because you flagged having incentives in place for a pilot project. We're assuming that you mean incentives from the federal government or federal government agencies. How much in incentives are you looking for? What's the cost of putting that pilot project in place?