Natural Resources Committee on Feb. 12th, 2013

[The Chair, Conservative, Leon Benoit]

Good afternoon, everyone, and welcome. We're here today continuing our study of innovation in the energy sector.

We have three witnesses with us today.

We have, first, from Encana Corporation, Richard Dunn, vice-president, Canadian division, regulatory and government relations. Welcome to you, Mr. Dunn.

From the Canadian Energy Research Institute, we have Peter Howard, president and chief executive officer. Welcome to you, Mr. Howard.

We have by video conference from Toronto, from Bullfrog Power, Tom Heintzman, co-founder and director. Welcome to you, Mr. Heintzman.

Today we'll just go through the presentations in the order that you're listed on the notice of the meeting, starting with Mr. Dunn from Encana Corporation.

Go ahead, please, sir, for up to 10 minutes.

[Richard Dunn, Vice-President, Canadian Division, Regulatory and Government Relations, Encana Corporation]

Good afternoon. I'm Richard Dunn, vice-president of government relations for Encana. I appreciate the opportunity to be here and talk to you on what innovation means to the natural gas industry in Canada. As you know, this is a significant industry that accounts for some 500,000 jobs.

Today I'll outline how innovation continues to change our business, not only from technical perspectives but also how innovation has brought industry-wide changes, structural changes, the likes of which are unprecedented in North American industry.

Innovation in the sector takes many forms, from incremental operating improvements to cutting-edge R and D efforts focused on improving both technological efficiencies and ensuring the resource is developed as responsibly as possible.

Encana, the largest natural gas producer in Canada, has been at the forefront of industry advancements such as pad drilling and multi-stage hydraulic fracturing. These huge technological leaps have allowed us to unlock natural gas from formerly inaccessible unconventional reservoirs, such as shale and tight rock formations. Innovative production methods, and development and deployment of cutting-edge technology, such as polycrystalline diamond bits, mean we've been able to access a wealth of natural gas resource in Canada, certainly estimated at well over hundreds of years of supply at current production rates—current production rates being some six trillion cubic feet a year, and recent estimates placed the western Canada resource at 4,600 trillion cubic feet, so a vast amount when compared to current production rates.

In addition to our own internal focus on innovation, we support external R and D efforts through third-party partnerships with academia. Recently, for example, Encana made a five-year pledge of $1 million to support research activity at the University of Calgary's Institute for Sustainable Energy, partnering with Alberta Innovates—Technology Futures, which is a Government of Alberta-sponsored organization dedicated to helping industries find solutions and move technologies to market. A portion of this investment was directed toward an endowed chair dedicated toward research in unconventional natural gas.

Backed up by cutting-edge core analysis facilities, the chair, along with associated grad students, focuses on unlocking the technical challenges of Canada's unconventional reservoirs, thereby further enhancing Canada's energy supplies.

The industry puts a high value on collaboration as it applies to innovation. At Encana, for example, we have an environmental innovation fund that has invested over $40 million over the last three years to economically improve the industry's environmental performance and to provide capital for projects that focus on implementing innovative technology.

A significant portion of these investments is directed to early stage start-up companies and industry projects. An example of this is the funding of Seal Well Inc.'s development and testing of ultra high-integrity well sealing plugs made of a fusible metal alloy. Targeted for use in the abandonment of wells at the end of their producing life, this product is being developed as a secure, long-life, and cost-effective alternative to conventional cement abandonment plugs.

Producers certainly recognize the importance of collaboration and innovating together on areas of responsible development. A good example of this is the B.C. implementation plan for the management of boreal caribou, established through the collaboration of industry partners along with the B.C. oil and gas commission and the B.C. ministry of the environment.

This plan manages access to land for development during the critical calving period and includes such items as promoting the use of meandering seismic lines, which limit the line of sight between predators and prey. Industry has committed to provide up to $10 million in funding over the next five years for boreal and mountain caribou research. In fact, just before coming here we were on a conference call approving the program for this year's research, a large part of which is collaring and tracking caribou and the calves.

Another item promoted in the boreal caribou plan is the use of pad drilling. Pad drilling means multiple horizontal wells are drilled from a single pad of about 250 metres by 250 metres on the surface. These wells tap into about 15 square kilometres of reservoir buried thousands of metres deep, accessing tens of billions of cubic feet of natural gas.

This innovation of the single pad eliminates the need for hundreds of vertical wells and well sites, along with associated roads and pipelines. It's a case where technological innovation has produced a win-win of cost-effective operations while minimizing the environmental footprint on the land.

As producers, we recognize that shale gas production is certainly a water-intensive process through the hydraulic fracturing, and we supported R and D efforts to ensure sound water stewardship. For example, in 2009 a collaboration of companies operating up in the Horn River Basin up in northeast British Columbia worked with the province of B.C. to examine non-potable water alternatives for our operations. This was accomplished through Geoscience BC, a provincially funded government organization that has launched a number of projects to identify and map subsurface aquifers suitable for water sources in the basin.

The Debolt source water treatment plant, a partnership between Encana and Apache, highlights the results of these efforts and provides a tangible example of companies working together to minimize surface water impacts. Supplying essentially all the water needed for both companies' hydraulic fracturing operations in the Two Island Lake area, the facility produces water from the Debolt formation, which is a deep subsurface aquifer containing saline water unfit for agricultural or human use.

Finding alternative water sources is just one way the industry, principally through the Canadian Association of Petroleum Producers, CAPP, has taken a proactive approach to address concerns regarding hydraulic fracturing. The industry has developed a series of industry-wide hydraulic fracturing operating practices, which are designed to protect the quality and quantity of groundwater. Companies are implementing these practices in real and meaningful ways. For example, all producers have committed to disclosure of chemicals used in hydraulic fracturing and have collaborated with provincial regulators to implement mandatory reporting systems of same.

Additionally, in Encana's case as well, we have worked closely with our fluid suppliers to implement the practice called the fluid additive risk assessment, with the result of moving to the use of greener hydraulic fracturing fluids. At Encana we're proud—having implemented this practice—of taking the step to eliminate the use of diesel, benzene, and heavy metals, such as cadmium, arsenic, chromium, lead, and mercury in our hydraulic fracturing fluids. Further, we have shared this work with both regulators and other companies operating in the industry.

Innovation is also apparent in the way industry is working to find new markets for our products. The advancements in unconventional natural gas have created a new supply and demand dynamic of sustained low commodity prices due to the great abundance of unconventional natural gas we've unlocked in the past few years. At the same time, our traditional customer, the United States, does not need us to the extent it once did, due to the prolific shale plays being developed south of the border as well. The U.S. market is shrinking dramatically for Canada, as is the level of U.S. investment in the Canadian natural gas sector.

In response, industry and Encana have embarked on a number of initiatives to boost domestic consumption, such as providing liquefied natural gas for a recently announced pilot by CN Rail that runs locomotives on liquefied natural gas. The environmental benefits of natural gas in transportation are clear, up to 30% fewer CO₂ emissions and up to 90% less smog-causing particulate matter. Continued government support and commitment to implementing the natural gas road map, which includes a commitment to research and development, will help hasten the transport sector's option of increased natural gas use.

However, increasing domestic consumption is clearly not enough; we also need to find new markets, with the U.S. market shrinking. Through Encana's partnerships with global investors such as China National Petroleum Corporation and Mitsubishi, we know that Canadian producers' technological sophistication and commitment to responsible development, along with Canada's supportive political and regulatory climate, are major enablers in attracting foreign direct investment.

This is important because we are witnessing a paradigm shift as we move from a model of U.S.-based investment and export to Asian-based investment and export.

Asian investors are seeking a reliable long-term supply to meet the needs of their growing economies. At the same time, Canadian producers need to diversify markets. This has resulted in industry applying its innovative focus to LNG export, with a number of terminals planned for the west coast.

The LNG market is rapidly evolving as these proposed facilities continue to advance to both project and regulatory approvals. Canada is very well positioned to supply feedstock to world markets, particularly Asia, where energy demand is robust and increasing.

Canada has a long, proud history as an export nation, and a political will exists both federally and provincially to diversify our markets for natural gas. This is crucial for the industry's continued success; however, Canada is certainly not alone in recognizing the export opportunity. We must all continue to implement policies that will provide us with a competitive and level playing field in order to compete with LNG projects in the United States and Australia.

The adoption of measures such as CAPP's proposed tax reclassification for LNG facilities will positively influence investment decisions still to be made for these west coast facilities and will ultimately help us realize the commercial potential of these new markets.

In closing, whether exemplified through operational improvements, support for research and academia, collaborative efforts by industry players to address stakeholder concerns and minimize the environmental impact, or by seeking new markets and end uses for our projects, innovation has been and continues to be fundamental to the success of the Canadian natural gas industry. That same spirit of innovation that has radically changed the industry in recent years will be just as pivotal in years to come as we capitalize on the new market opportunities before us while leading the way in responsible development of the world-class resource we're endowed with.

Thank you very much.

[The Chair, Conservative, Leon Benoit]

Thank you.

We go now to Peter Howard, president and chief executive officer of the Canadian Energy Research Institute.

Go ahead, please, with your presentation, sir.

[Peter Howard, President and Chief Executive Officer, Canadian Energy Research Institute]

Thank you, and good afternoon, everyone.

My name is Peter Howard, and I am the president and CEO of the Canadian Energy Research Institute.

Founded in 1975, the Canadian Energy Research Institute, commonly referred to as CERI, is an independent, not-for-profit research institute specializing in the analysis of energy economics and related environmental issues in the energy production, transportation, and consumption sectors. Our mission is to provide relevant, independent, and objective economic research.

CERI is a fully funded institute, with funding coming from the Government of Canada, the Government of the Province of Alberta, the Canadian Association of Petroleum Producers, and the Small Explorers and Producers Association of Canada. In addition, in-kind funding by the Energy Resources Conservation Board of Alberta and by the University of Calgary is well accepted.

Concerning the gas industry in Canada, my comments today will be focused on the gas industry in western Canada and on how innovation has contributed to the competitiveness of that industry.

The natural gas industry in western Canada is currently under pressure due to low commodity prices, resulting in economic challenges for many exploration and development companies. Low commodity prices are a direct result of an oversupply situation in the market, coupled with a flat- to low-growth demand profile for natural gas within the North American market.

Surprisingly, this oversupply situation is a direct result of an innovative process developed by the oil and gas industry. I am referring to the advent of the horizontal drilling and hydraulic fracturing process. Low commodity prices are not new to the industry, but current research suggests that today's prices are here to stay for the medium to long term. This fact, when coupled with higher operating costs, weather issues, remote locations, and higher pipeline transportation costs, results in a situation in which the economics of gas development are severely challenged.

Research carried out by CERI is or will be available on CERI's website as a result of our mandate and is available to government, industry, and the general public at large. Specifically, the following reports will offer a background for my comments today. The North American natural gas demand pathways study is one we have been involved in for the last eight months; it is due to be released in March of this year. Global LNG: Now, Never , or Later is a report that we just published in January of this year. Thirdly, Improved Productivity in the Development of Unconventional Gas is a report that we published in May 2012 as a joint report with CSUR, the Canadian Society of Unconventional Resources, and PSAC, the Petroleum Service Alliance of Canada.

The development and widespread application of horizontal drilling coupled with multi-stage hydraulic fracturing has revolutionized the industry. Utilizing these innovative technologies has allowed development of hydrocarbon-bearing formations that in the past has not been deemed to be economic. The rapid development of shale and tight gas resources in the United States and Canada has created an environment in which natural gas supplies are projected to last many hundreds of years.

Unfortunately, this rapid development within the United States has added close to 15 billion cubic feet per day since 2005, creating an oversupply position. Of more concern, it is starting to back Canadian gas out of historic markets within the U.S. mid-continent, the U.S. east coast, and Ontario and Quebec.

CERI's report on natural gas pathways starts with the assumption of a continuing robust supply within the United States and explores four plausible narratives for future gas demand within North America. This report suggests that the term “robust supply” can be loosely translated into a supply swing of plus 45 billion cubic feet a day by the year 2030.

Two issues that are identified as potentially having the largest effect on gas demand are LNG exports, whether off British Columbia or from the Gulf Mexico, and the transition of coal-fired power generation to natural gas-fired power generation.

The future viability of the western Canadian gas industry is dependent on access to markets, whether North American or outside North America’s shores, coupled with a resource that can be developed and be price-competitive.

The four narratives that were examined in this particular study indicated that the Henry Hub price will, on a low case, remain within the $2.50 to $3.50 per mcf for the next 15 years, and on a high case climb back to the $6 level by 2020 and the $7.50 level by 2030. The low case is the most concerning because it suggests that AECO C pricing, which is the benchmark price for western Canada development, will stay at or below the $3 per mcf for the foreseeable future.

The four narratives also indicated that the level of net gas exports to the United States will decline from the current level of 4.5 billion cubic feet per day to a sustained level of 3 billion cubic feet per day in the high case, to a negative position in the low case. In other words, following the low case of our four scenarios, Canada could become a net gas importer of natural gas within the coming years if the low case becomes reality.

In drilling terms, this could be considered weak, if not devastating, as activity will remain below 1,000 wells per year for several years to come. Even though a current horizontal well with 6 to 12 frack storages effectively replaces 6 to 8 vertical wells, the activity is still small when compared to the 18,200 wells that were drilled in 2006.

CERI's LNG report concluded that the proposed British Columbia LNG terminals are faced with increasing competition for access to the Asian Pacific markets, coupled with the potential of a changing price regime. Australia has seven liquefaction projects under construction, while the United States has thirteen liquefaction projects in various phases of development. This, coupled with East Africa developments and the B.C. projects, results in 25 billion cubic feet per day of new LNG supply potential all vying for the island economies of Japan and Korea and the mainland economies of China and India within the 2015 to 2020 timeframe.

Japan, from a security of supply position, will purchase LNG based on an oil-linked contract, whereas Korea is looking to buy LNG at the point of liquefaction, as in the recently announced Sabine Pass contract. China, on the other hand, is using its size to negotiate down LNG prices, still oil linked, but potentially to the point of delinking from oil will be a reality. The development of an LNG trading hub is a potential for the Asian Pacific market.

With respect to western Canadian gas producers, the above suggests that the LNG game has significant risks, and as in the case of a low-priced North American market, being a low-cost producer is paramount.

Prior to the advent of the horizontal well, gas producers drilled one well per section of land and per geological formation. In rare cases, multiple production strings were used to access multiple segregated geological structures, all within one casing. In addition, some geological structures were allowed to be commingled in a single casing but under strict guidelines from the regulator. The development of the horizontal well, against constant pressure to reduce costs, resulted in the innovative approach of multi-well pads.

The practice of grouping wells tightly on a single land location has been driven by environmental, economic, and practical logistics around materials and land footprints, but in the end it is all about reducing costs so that the unit cost of production can compete in the marketplace, which currently is approximately $3 per mcf.

The practice of placing multiple wells on one pad results in the following benefits: it reduces the impact on developable land; it reduces the need and extent of access roads and gathering pipelines; and it allows for continuous drilling over a longer period of time, including winter and summer conditions. A single rig could drill up to 30 wells without the cost of mobilizing and demobilizing that rig. It allows for continuous fracking operations without the need to reposition the pumps, trucks, and pipes; it allows for central storage of materials, including drilling pipe, fracking fluids, sand and water; it allows for improved supply chain management by having full loads of materials travelling from the warehouse to a single location; and finally, it reduces travel time for crews and supervisors to one site as opposed to multiple sites.

In very simple terms, by applying the economies of scale—multi-well paths—across the elements that contribute to the total drilling costs, the per-well costs drop by more than 25%. In concert with multiple well-drilling operations, the cost advantage of moving from a three-stage frack process up towards a 12-stage frack process decreases the supply cost to a range of $3 to $4 per mcf, depending on the responsiveness of the resource location.

In 2011, in the province of Alberta 2,059 gas-directed well licences were issued; 92% of all the licences that were classified as horizontal licences were located within the west-central part of Alberta. Within this area, 25 companies licensed 20 wells or more, and it is strange to note that only 24% of the horizontal well licences involved two or more wells. In fact, there was only one location—and I have to give credit to Encana—with 12 wells on that site, one location with six wells, and 25 locations with four or five wells. Please note that I'm talking about Alberta here. British Columbia is slightly different.

While the industry embraces the application of multi-well pads in pursuit of unconventional resources, the development appears to remain focused on one to two wells per section. Possible reasons for this include budget constraints for some exploration and development companies, a condition that will worsen as gas prices remain low; single wells being drilled to continue the land tenure while waiting for a price improvement to fully exploit the reservoir; and some unconventional resources still being considered exploratory resources, for which the potential and the risk have not yet been evaluated. Low market prices weigh heavily on that type of decision.

Having fragmented land holdings reduces the desire for multi-well pads. Large development companies will only use multi-well pads if they have land control in offsetting sections. In Alberta, the nature of the beast is that we have a fragmented land system.

Western Canada will continue to face challenges relating to competing for space in North America or the Asian market, and in order for the industry to achieve success in this game, continued improvements in productivity through innovation are an absolute requirement.

Thank you for your time and attention.

[The Chair, Conservative, Leon Benoit]

Thank you very much, Mr. Howard, for your presentation.

We go now by video conference to Toronto, to Tom Heintzman from Bullfrog Power.

Go ahead, please, sir, with your presentation.

[Tom Heintzman, Co-founder and Director, Bullfrog Power]

Hello there. My name is Tom Heintzman. I'm the director and one of the co-founders of Bullfrog Power.

Bullfrog Power is Canada's renewable energy choice. We provide a renewable energy choice to Canadians coast to coast.

The premise behind Bullfrog Power is relatively straightforward. In all of the other products and services that Canadians buy, they have environmental choices, whether that's transportation, clothing, articles for their house, or food. However, historically they have not had an environmental choice in energy. It's always been “one size fits all”, and you get what you get when you plug in, despite the fact that energy is the biggest contributor to an individual's environmental footprint. So the simple proposition is to give people a choice, just as they have choices in all these other products and service categories, to pay a premium to purchase a green, renewable product.

We inject onto the electricity grid or the natural gas pipeline system as much renewable electricity or renewable natural gas as our consumers use. They pay a bit of a premium, and that premium goes to helping make new renewable projects economical.

New renewable projects across Canada require a bit of a premium. Typically, that premium is paid by a government entity or a utility on behalf of ratepayers. Bullfrog is a voluntary initiative that is additional to and supplemental to these government initiatives. Government initiatives will increase the amount of renewable power by a certain amount through procurement, and the voluntary consumers, who are choosing to pay more, can increase it even further.

This model has been quite successful in the United States. It's estimated that as much as a third of the new renewable power in the United States was funded by voluntary consumers.

Bullfrog currently gives consumers both a renewable electricity choice and a green or renewable natural gas choice. Renewable natural gas is very new in Canada. It's methane that's produced by compost, by your organic waste. We clean up that gas and inject it into the natural gas pipeline to displace conventional natural gas. It's called biomethane, and the facility that is providing it for our customers is the first of its type in Canada. But we expect many more of these over the years to come.

Thousands of Canadians are making the choice to pay a premium and purchase renewable electricity. These include homes from British Columbia to P.E.I., as well as businesses, such as RBC, TD, Unilever, Walmart, and about 1,500 other businesses. These entities pay a little more to buy renewable electricity. They reduce their environmental footprint as a result and they support the development of renewable energy in the country.

That's the background in terms of Bullfrog. I would not be doing my company a service if I didn't give some recommendations as to where we would hope that policy could move. Some of these levers will be next to impossible to move; others are more changeable.

First of all, we're very fortunate to have been able to create a business model that can work coast to coast, but there are a number of impediments to innovation in our space, in the downstream electricity and natural gas markets.

First, provincial regulation of energy leads to a patchwork of regulations and makes scaling a business across the country very challenging. This is a constitutional matter, so obviously quite difficult to deal with.

Second, the turnover in ministries and bureaucracies results in shifting policy that's not conducive to long-term energy planning and investments. Here in Ontario we're on our eighth minister of energy over the course of the last eight years.

Third, utilities, which tend to control both natural gas and electricity markets in Canada, tend to be very change-resistant. Even their economic incentives are not always aligned with innovation.

Fourth, markets in which innovation tends to flourish are not common in the downstream energy space in Canada.

Fifth—and here is a policy recommendation, and I'm certainly not the first to make it—putting a price on carbon would certainly help drive innovation in the renewable energy space as well as in conservation.

Last, our business model is so small that this concept of citizens voluntarily paying to take environmental action is still so unusual that it is not taken account of by regulatory or administrative bodies when they make policy decisions.

As a very small example of this, because of the small size of the voluntary renewable energy market, Environment Canada and Stats Canada will not separate, for the purposes of national reporting, the electricity purchased by voluntary green customers from the electricity purchased by the other customers. As a result, there is a fundamental difficulty in separating those two pools of energy, which makes for double-counting and complicates the reporting, the claims, and ultimately the development of a voluntary renewable power market in Canada.

Those would be five policy observations and comments that I have.

[The Chair, Conservative, Leon Benoit]

Thank you very much, Mr. Heintzman, for your presentation from Bullfrog Power.

We go now to questions and comments, starting with Mr. Calkins for up to seven minutes.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

Thank you, Chair.

I'm going to start by getting some clarity. Mr. Dunn, last week we had the Environment Commissioner before this committee. In his report he talked a little bit about hydraulic fracturing and some of the disconnects. I was a little bit critical of him, being a rig worker myself. I've been out on the rigs when the fracturing trucks show up. I had to take all my courses, whether it was transportation of dangerous goods, workplace hazardous materials, information systems, or material safety data sheets. So I know about all of these chemicals, all the safety measures, and all the information on these safety sheets. They said there was a big disconnect between departments and agencies about what's actually going into the ground, yet your testimony seems to be clear about what the companies have to disclose and about the knowledge of the fracturing chemicals that are going down the well.

For the sake of clarity, can you tell us whether hydraulic fracturing operations in British Columbia and Alberta are required to disclose the chemicals that are used?

[Richard Dunn]

The short answer to that is yes. Disclosure is mandatory in both British Columbia and Alberta. British Columbia was brought in, in 2012, and Alberta was brought in, I believe, on January 1 of this year. So in all cases, the answer is yes.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

Before that, it was an optional thing for a company to go down that road, right? I'm not going to ask specific questions. You can volunteer the information if you want. Some companies would and some companies wouldn't. But there have also been a lot of technological advances in hydraulic fracturing that have allowed a complete change in the economic environment in North America. For example, the United States is moving towards energy independence, because changes in technology have enabled them to get at what was previously unattainable through the technology of the day. There are some trade secrets that needed to be there. But in the interest of environmental considerations, I think companies looking for what is deemed to be the social licence have been proactive, have they not, in disclosing their business practices in respect of what's been going down the hole?

[Richard Dunn]

Absolutely. Certainly, public awareness of hydraulic fracturing operations has in part led to industry's commitment to disclose. The websites that enable us to disclose were pulled together, I would say, roughly about a year before the reporting was made mandatory. Industry adopted disclosure at that time on a voluntary basis and, as I say, worked with regulators to recommend that the regulations be put in place to reinforce that and give the public assurance.

To your point about technological advancements and trade secrets, certainly the chemicals are protected under intellectual property. We can only give what the material is. We can't get into the details of that. That's reflected on the disclosure where there are intellectual property restrictions. That is on the disclosure. Other than that, all chemicals and materials are fully disclosed.

Interestingly, more and more of the materials—not to elaborate on it too much—or the chemicals that have intellectual property restrictions are the green chemicals. That's what the suppliers are.... As I mentioned, we looked at the risk, and as a company we moved towards saying that we would not accept the risk of benzine and certain heavy metals included in our fracturing. As a company we looked at that. It's still legal to use. There are operating practices that can safely manage them, as you mentioned, but we just felt that's not where we were going to go—hopefully leading the industry in some way, shape, or form.

Those newer, greener chemicals are often the ones that have the intellectual property issues associated with them, so when you see that you've got some restrictions in terms of disclosure, those are actually in many cases the greener chemicals that industry is moving towards.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

That's quite interesting. In terms of managing the chemicals being used for the wells being drilled at your particular company, then, how do you go about that disclosure?

We did some research on the frackfocus.ca website, and the hydraulic fracturing fluid product component information disclosure form is there. Are you familiar with that? It explains the chemicals used in fracking operations. Do you have any examples that would benefit this committee of what kind of information is on that form? If it's public information, what could the public, and for that matter the environment commissioner, have access to, or what should they have had access to?

[Richard Dunn]

Certainly you would see the types of chemicals we use and the purpose. We're pumping large volumes of water and sand, principally, in fracturing operations. In doing so, you want to minimize the energy required to do that. So you put in, for example, trace amounts of chemicals that are friction reducers that will slick up the water. That will be mentioned on there.

As well there might be.... Oftentimes the water comes from subsurface, as I mentioned in my talk, but when you're just starting out a development, you'll oftentimes get water from surface water supplies, assuming the capacity is there. This water tends to have bacteria in it that could foul your formation, so you'll add in a biocide to take care of the bacteria.

The chemicals would be listed on that form, and the purpose, as I mentioned, as gelling agent or biocide. Furthermore, it would have information that.... It's all transparent and available to the public on a location-by-location basis in terms of the actual chemical names, the company, the supplier, the components, and the chemical abstract number. So it's very detailed information.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

There's complete traceability of everything that's being used.

[The Chair, Conservative, Leon Benoit]

Mr. Calkins, your time is up.

We go to Mr. Julian for up to seven minutes.

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

Thank you, Mr. Chair.

Thanks to our witnesses. It's very interesting testimony.

I'd like to start with you, Mr. Heintzman.

It's very interesting that you referenced putting a price on carbon. It's certainly what the CEOs and presidents, even in companies in the oil and gas industry, such as Total and Cenovus, have been saying, and recently Shell Canada as well. Very clearly, this is part of an ongoing debate that has to take place in a mature framework, and we're certainly hoping they continue to bring that mature discussion on this important issue.

I'm very interested in your reference to procurement process. I'd like you to give us a little more detail about that. Are you talking about governments in Canada or governments in the United States that have included renewable energy as part of their procurement plans?

[Tom Heintzman]

Typically, when I'm talking about that, it's not the government entity itself that is procuring, but a government agency on behalf of ratepayers. For instance, in Ontario, the Ontario Power Authority is procuring renewable energy and then passing that cost on to the ratepayers. It's trying to increase the amount of renewable energy by something less than 10%.

In British Columbia, it's BC Hydro, typically, that procures it. In Nova Scotia, it's NSPI. Most jurisdictions in Canada have a goal for increasing the amount of renewable power in the province and there's some entity within that province that's in charge of contracting for that.

That's separate from governments purchasing, on their own behalf, renewable power. But you do see that on occasion, so we have a number of cities and municipalities that would be buying renewable power. The Ministry of the Environment in Ontario is buying it for its own operations. In the past, various entities of the federal government have bought renewable power for their own operations. In fact, Transport Canada is currently a customer of Bullfrog Power.

In addition, in the United States, both those things occur, so you have on one hand governments procuring for ratepayers and governments procuring on their own behalf for their own consumption.

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

You said in the past that the federal government has looked at renewable power. Has that amount increased or decreased over the past few years?

[Tom Heintzman]

It would have decreased over the last several years. I don't have the numbers at my fingertips, but there was a green power procurement program that would have ramped up in the late 1990s, early 2000s, and that would be diminishing now.

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

That's helpful to know. Basically, we've gone backwards in terms of procurement with the federal government.

Going to the voluntary purchases, you particularly referenced in the United States that you have consumers going out and paying a margin for renewable green power. What's that differential right now, if you can give us a couple of examples, and how much do you generate across the country and in the United States?

[Tom Heintzman]

Bullfrog Power only operates in Canada. In the United States the average residential.... They sell to homes or the residential market and then the business market. Just for the sake of reference, there are about 860 green power programs in the United States, so 860 utilities selling green power to consumers, giving them a choice.

The average price mark-up there would be in the 1.5¢ to 2¢ range. Say the average power price is something in excess of 10¢, 12¢, so you know it's a 10% to 15% mark-up. In Canada, we're in the 2¢ to 3¢ range in terms of the premium consumers would pay. Again, that's on a landed cost of 11¢ or 12¢, so something less than 20% to 30%, call it 15% to 25%. I think that answers your questions.

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

What it doesn't answer is the issue of how many consumers roughly have been willing to pay that differential and how much you're able to sell.

[Tom Heintzman]

Right. Bullfrog Power would sell in the order of 500,000 megawatt hours a year, approximately, which is a very small amount in the grand scheme of things in Canada.

In the United States the average program—and these are programs that are run by utilities and are not particularly well marketed—has a 2% penetration rate. The most successful programs have a penetration rate of over 25%. Bullfrog Power would be a fraction of 1%.

One of the big levers to increase the penetration.... Where you see the highest penetration is where a company like ours is able to cooperate with the utility to market the green power. So imagine getting your bill—whether you get it from Ottawa Hydro...I'm not sure who you get it from—and having a choice at the bottom that allows you to pay a premium for renewable power. That's what really drives the take-up in the United States.

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

Thank you. That is all very helpful.

We're clearly hearing from you that government policies do make a difference. Certainly in Manitoba the NDP government has brought forward a very innovative energy efficiency program that has helped to bolster the energy efficiency of that province. Those are the kinds of innovative programs we have to look at.

I'm going to move on to Mr. Howard. Thank you for being here.

You referenced a number of studies that the institute is currently working on. Because of the increasing debate around value-added, of course, I'm interested as to whether or not the energy institute is looking at value-added and its potential in Canada. I'm citing Jeff Rubin, a former chief economist for CIBC World Markets, who has said very clearly that part of the problem that we have with the glut right now is that we're not doing the type of value-added transformation we need to. He cited Suncor as a company that isn't subject to the same price differential, because of course it does value-added and reaps the profit, rather than sending it down to another market in another country to get that value-added increase.

Are you currently doing any studies on that? Is that something that interests the institute?

[The Chair, Conservative, Leon Benoit]

Mr. Julian is out of time, Mr. Howard, so we'll have to have a short answer. Go ahead, please.