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Home > Speeches and Presentations > Speeches and Presentations 2007 > Hydrocarbons and Canada's Energy Future

Hydrocarbons and Canada's Energy Future

Presented by
Gaétan Caron
Vice-Chairman
National Energy Board

Association Pipeline
Club St-Denis, Montréal

22 February 2007

There could not have been a better time for me to be invited to speak before the Association Pipeline. First and foremost, it is always a good time for me to be in Quebec, where I grew up and where I have family and many friends and colleagues. And, on the energy scene, more than ever energy is central to the future of our society, from an environmental, social and economic standpoint. Citizens are trying to reconcile their goals and ambitions: a prosperous economy, responsible development, environmental gains, and a just society. Energy is a key consideration in seeking to attain these goals and fulfill these ambitions.

Hydrocarbons are central to Canadian energy. They are very important to the current equilibrium between supply and demand, and most forecasts predict a continuing importance in the foreseeable and long-term future.

Today, I will present to you my perspective on:

the importance of hydrocarbons in Canada and in Quebec
the supply of, and demand for, hydrocarbons
the related need for infrastructure, the issues related to the development of hydrocarbons
what's on our plate public hearing wise involving hydrocarbons, and
the manner in which I see the NEB as a partner in the responsible development of hydrocarbons and energy

Present in every day's life

Hydrocarbons represent the largest portion of all energy demand in Canada today. Each of us use them everyday, in one way or another. There is growing concern how much hydrocarbons we use, and how wisely we use them. At the same time, according to most energy demand forecasts, this reliance on hydrocarbons in Canada is likely to continue. The question most people ask is not: "should we continue to develop hydrocarbons?". It is rather: "how and at what pace should we do so?".

Importance in Canada - 2004

As a primary fuel, hydrocarbons contribute to around 77% of all energy demand in Canada today. Oil and oil products represent the largest portion, fuelling around 38% of Canada's energy demand.

In Quebec today, hydrocarbons contribute to 57% of energy demand needs. Oil and oil products represent the largest portion of demand in Quebec, fuelling around 44% of Quebec's energy demand. Hydro demand represents the second largest portion of Quebec's energy demand at 31%, meeting a lot of the province's electrical needs (source - Statistics Canada).

These numbers are somewhat different when looking at energy end use. For instance, the Quebec Energy Strategy indicates end use consumption in 2003 was 38.5% oil, 12.1% gas, 0.9% coal, and 38.5% electricity and 10.0% biomass.

Importance in Canada - 2005

This reliance on hydrocarbons in Canada is most likely to continue. It is not uncommon for future projections to envisage hydrocarbons remaining the same at around 76% of all Canadian energy demand.

Quebec's reliance on hydrocarbons is likely to continue in the future.

A lot of this trend has to do with transportation.

Natural Gas Supply

Let's examine how much gas we can expect to be available in the future (Source: NEB Energy Futures Reference Case + Continuing Trends scenario (preliminary results)).

Western Canada Sedimentary Basin

Western Canada accounts for 98% of current Canadian gas production. Conventional production from this area has been relatively flat since 1999 and is just now starting a very gradual decline.

Total gas deliverability from the Western Canada Sedimentary Basin is supported by a growing contribution of coalbed methane. You can see on the chart to the left what would happen if we stopped drilling new wells, and if coalbed methane were not developed.

East Coast

Sable production continued to vary between about 300 to 400 MMcf/d in 2006. Initial production after Sable gas went onstream in year 2000 was over 500 MMcf/d and has gradually declined since. With the start up of offshore compression at the end of 2006, production could be boosted back to close to the original peaks.

A Benefits Agreement has been signed on the Deep Panuke project. If this gas comes onstream, it could add 300 MMcf/d of gas supply coming from the East Coast. The earliest gas could flow into the pipeline is 2010. A hearing will be held on the project in March 2007.

The North

Regulatory work regarding the proposed Mackenzie Gas pipeline is ongoing. The Applicants have proposed a 1.2 Bcf/d pipeline. I'll say a bit more about this later.

Coalbed Methane

I spoke earlier about the role CBM may play in deferring the decline in natural gas production from the Western Canada Sedimentary Basin.

CBM is simply natural gas contained in coal seams. It is primarily composed of methane. During development of coal, organic material from plants and trees becomes carbonized or coalified by the effects of heat, pressure and geologic time. During the process, large amounts of methane are generated and the majority of the methane is adsorbed (chemically bonded) onto the surface area of the coal while smaller amounts are contained as free gas within the fracture system (cleats) of the coal.

CBM production represents just over 2% of Canadian production - a bit more than Sable gas. According to the Alberta Geological Survey, the size of the in-place NGC resource in Alberta may be as large as 500 Tcf, with another 90 Tcf in B.C. The NEB carries an estimate of about 60 Tcf being economically recoverable, but these estimates involve a high degree of uncertainty due to the early stage of CBM development.

Coalbed Methane Well

CBM is produced by lowering the pressure in the coal seam - either by removing water if the seam is wet, or just by releasing pressure through the well if the seam is dry. Almost all the CBM developed to this point in Alberta is dry and falls into this latter category. In cases where water is encountered, it is usually salt water and is re-injected below ground into salt water aquifers, with flow rates tending to be relatively low.

A major difference from conventional wells is that NGC wells decline at a lower rate than conventional wells. For dry coals in Alberta, gas production is maintained at a relatively stable rate over the initial 12 to 18 months and then begins a gradual decline. Declines have been in the range of 6 to 12 percent annually after the peak year. By contrast, a typical conventional well may have an initial decline of 50 percent, followed by a 24 percent decline in the second year of production.

Gulf of St. Lawrence

Many of you will know more than I do about potential natural gas supply and exploration in the Gulf of St. Lawrence. My understanding is that after some seismic work, environmental assessments and public consultations, this region is being re-assessed.

The recoverable gas potential in the Gulf of St. Lawrence was originally estimated at 1.4 Tcf by the Geological Survey of Canada. We understand that the GSC is in the process of updating this estimate.

A key subject of this update will be the "Old Harry" prospect. It is considered one of the largest undrilled prospects in this area - in 1500 feet of water in the Laurentian Channel. This structure straddles the Quebec/Newfoundland boundary. The area is awaiting an agreement between Quebec, Newfoundland and Labrador and the Federal governments before the prospect can be opened for drilling. Industry estimates that 1.5 to 2 billion barrels of oil (if oil) or 4 to 5 Tcf of gas (if gas) could theoretically be contained in such a structure.

Onshore exploration in the St. Lawrence Lowlands (in the Centre-du-Québec region) and on the Gaspé peninsula is also attracting the interest of the industry.

Crude Oil Supply

Western Canada Sedimentary Basin

Canada's oil sands define the shape of the future production of oil in Canada. As the graph shows, as is the case for conventional natural gas supply, conventional oil production in western Canada is in decline. However, the oil sands have the potential to increase Canada's total oil production significantly, from 2.5 MMb/d to 4.1 MMb/d by 2015. I will say more about the oil sands in a minute.

East Coast

In 2005 the White Rose Field joined Hibernia and Terra Nova to become the third producing field in the Jeanne d'Arc Basin offshore Newfoundland and Labrador. This basin's production in 2007 is estimated to be 400 000 b/d, up 25% since 2005. In the 2010-2015 timeframe, it is anticipated that the Hebron Field would come on stream, as well as other, smaller satellite pools. There is active exploration being carried out in the Orphan Basin, with good potential for a sizeable discovery before 2015.

(Source: NEB Energy Futures - Reference Case (preliminary))

World Oil and Bitumen Resources

Today, Canada produces 3 MMb/day of an 81 MMb/d market (4%). Our proven reserves amount to 16.5 billion barrels (conventional + oil sands in development) (1.4% of world). But the total amount of Canada's oil sands (bitumen) that could be developed is 300 billion barrels - equivalent to 25% of the world's remaining proven reserves.

Canada is estimated to have the world's largest bitumen resource (300 to Venezuela's 270 billion barrels) although Venezuela has more total resource due to its larger conventional oil component.

Oil Sands Areas

Canada's oil sands resources are contained in three distinct areas: first, the Athabasca area which is the largest, and, to date, has seen the most intense development. This area is also the only area amenable to surface mining. Second is the Cold Lake area which has been responsible for the majority of in-situ production. Lastly, the Peace River area is the smallest of the three and has seen more modest development.

First Method - Mining

Today's mining operations use giant electric shovels to load trucks capable of hauling up to 360 tonnes. Mined oil sand is taken to a crusher which sizes the ore so that it can be transported to the extraction plant as a slurry. During extraction, the bitumen is separated from water, sands and other materials in preparation for upgrading. Upgrading is the final stage of the process whereby tar-like bitumen is converted into refinery-ready synthetic crude oil and, in some cases, petroleum products.

Second Method - Oil Sands In Situ: SAGD

Steam-Assisted Gravity Drainage (SAGD) is the dominant technology being used today to access oil sands deposits that are too deep to be surface mined.

The SAGD process uses a pair of closely spaced horizontal wells in which the producer well is positioned near the bottom of the reservoir and the steam injection well is positioned directly above. Steam is continuously injected into the upper well to melt the bitumen and allow it to drain into the production well where it is pumped to the surface.

In 2006, in situ production is estimated to be 483,000 b/d in comparison to mined production of about 648,000 b/d, for a total of about 1.1 MMb/d. Our estimate, and it is just an estimate, is for oil sands production to reach nearly 3 MMb/d by 2015 - this represents our best view of the maximum feasible pace that these large projects can be developed.

Unlike in surface mining, in situ operations have not traditionally included upgrading facilities to convert bitumen to synthetic crude oil, instead bitumen is marketed as a lower-value diluent-bitumen blend. This will change in 2007, when NEXEN/OPTI start up a combined in situ/upgrader project at Long Lake.

A major cost of in-situ operations is the natural gas component which is about one-third to one-half of the production cost.

Liquefied Natural Gas

We cannot talk about hydrocarbon development in Canada without talking about the potential for imports of LNG. Global LNG supply took a major jump in 2006 with liquefaction capacity rising by over 10 percent to about 24 Bcf/d. However, LNG remains a seller's market with import capacity well in excess of supply.

There has also been significant growth in the LNG tanker fleet to the point that about 30 of the 200 tankers in service are not committed to specific routes and are able to be redirected to the markets offering the best price. This has introduced a new era of flexibility into the LNG business

LNG imports into North America in 2006 (all through the U.S.) averaged about 1.5 Bcf/d or about 7 percent of the overall LNG trade. LNG imports into North America were actually down about 8 percent over the previous year due to an improved domestic supply position and lower prices than in 2005.

We have seen estimates of LNG imports into North America growing by a factor of 9 by 2015 (for instance, Ziff Energy projects 13.4 Bcf/d of imports by 2015).

I will talk later about a few LNG import projects of direct relevance to Canada.

Role of Emerging Technologies

As we address our mind to the development of hydrocarbons, we need to remind ourselves that meeting overall demand for energy in Canada and Quebec is about making our overall energy system work. More than ever, meeting future energy demand requires effective strategies to conserve energy and to develop renewable sources of energy. While the NEB's mandate has a lot to do with the assessment of gas and oil pipeline projects, our analysis of these proposed projects and our market monitoring functions require us to look at the big energy picture. In March 2006, we published an Energy Market Assessment on emerging technologies in electricity generation, such as wind power, small hydro, biomass, geothermal energy, solar photovoltaics, fuel cells, ocean energy, clean coal and demand management. Among the main conclusions of that report, I will cite:

Currently, there is low penetration of emerging technologies in power generation.
Developments in energy markets have created the conditions for rapid growth in emerging technologies.
A number of public policy mechanisms can promote the development of emerging technologies.
Demand management has the potential to make immediate and substantial contributions.

Clearly, as we envisage the development of hydrocarbons, we must consider the development of all energy sources, and their intelligent use. Emerging technologies must be a key aspect of our energy strategies. The 2006 Quebec Energy Strategy exemplifies that.

For all the details, please refer to: Emerging Technologies in Electricity Generation - Energy Market Assessment - March 2006 [PDF 4349 KB].

Adequacy of Infrastructure

Having now reviewed the supply and demand for hydrocarbons, we will now look at the infrastructure in-between. Is it adequate? What are the projects on the horizon?

The first of these two questions is addressed in the Board's Energy Market Assessment entitled "Canadian Hydrocarbon Transportation System Assessment", published in June 2006. It is the second edition of what we expect will be a publication we will continue to update periodically as conditions dictate.

The main conclusions of the June 2006 report are:

There is adequate capacity in place on existing natural gas pipelines.
Capacity is tight on oil pipeline transportation systems.
Shippers continue to indicate that they are reasonably satisfied with the services provided by pipeline companies.
NEB-regulated pipeline companies are financially sound.

Hydrocarbon Development Issues

Needless to say, there are issues related to the development and use of hydrocarbons in Canada. In many cases, there are broad policy issues that are properly under the purview of governments. They are about the choices society must make to prepare for a sustainable future. There are also more specific issues related to energy infrastructure projects that regulators such as the NEB are responsible for. For example:

economic issues: how can we create a regulatory environment that enables potential investors in energy projects to commit to projects that are found to be in the public interest?
social issues: what are the impacts, positive and negative, on communities potentially affected by a proposed energy project? How can we leverage the positive impacts, and how can we mitigate the negative impacts?
environmental issues: what are the impacts on the environment affected by a proposed energy project? How can we avoid or reduce these impacts, at the design stage, and how can we mitigate these impacts, during construction or operation?

Under our broad mandate, the NEB integrates, in its decision-making, all three components. The drafters of the NEB Act, when they sat down in the late 50's to create the new legislation, anticipated the basic foundation of sustainable development formulated at the Earth Summit in Rio in 1992. Under our Act, each and every decision of the NEB must integrates, in one overall finding, the economic, social and environmental factors. This integration is critical to the NEB's decision to approve or turn down a project, and, if approved, under what specific conditions.

Environmental Oversight

With respect to environmental factors, the NEB is there for the full life-cycle of facilities, from planning and design, construction, operation and abandonment.

I will give a few examples of how, in practice, we fulfill our environmental mandate:

planning and design: our Filing Manual provides exhaustive requirements as to how a proponent must integrate environmental factors in the design of facilities. Applicants are required to provide an appropriate level of detail represented by a set of facts and a transparent and defensible line of reasoning that is sufficient to support identified issues, analysis and conclusions with respect to the environmental and socio-economic effects of the project.
construction: when we approve a project, there are conditions attached to the certificate or order. For example, on a recent project, we stipulated that the company must file its Environmental Protection Plan and Restoration Plan for the project, for approval prior to commencement of construction.
operation: our inspectors audit and inspect facilities that have been authorized to be open for service by the NEB. For instance, during a recent operations and maintenance inspection near an environmentally sensitive area, we found that the company had demonstrated excellent compliance with the environmental protection requirements for the site, and confirmed that the continuous improvement aspect of the company's management system was being applied through the use of the company manuals.

These examples demonstrate how, in exercising its mandate, the NEB addresses in an integrated way the environmental factors that are related to the development of hydrocarbons under its jurisdiction.

Mackenzie Gas Project

I will now review some of the infrastructure projects on the Board's plate, and some we expect to be filed with us in the future. Some of them are already in the process of being assessed by the Board, so you will understand that I will not be talking about the merits of any of these projects, but a quick overview of the status of the regulatory process may be of interest to you.

The Mackenzie Gas Project is about 1400 km of pipeline, three compressor stations, and a capital cost estimate of $7.5 billion, which may be revised by Imperial Oil in the next few months.

The NEB completed in December 2006 the hearing days it has planned for the evidence phase of the hearing. So far, we have had 47 days of hearings. The related environmental assessment conducted by the Joint Review Panel is still in progress, and is expected to be completed later this year. Once the Joint Review Panel Report is made public, it will be incorporated into the NEB's record and we will then be able to proceed to the final argument phase of our hearing, and then deliberate and decide.

There is another pipeline project related to Northern gas resources, the Alaska Highway project, also shown here on this map. Discussions within industry and with various levels of government about this project are underway, both in the U.S. and in Canada. Regulatory filings with respect to this project depend on the successful completion of these discussions.

Gros Cacouna Receipt Point

On 16 April 2007, in Quebec City, we will begin our hearing on the proposed addition of a new delivery point in the TransCanada tariff. The receipt point is related to the proposed Gros Cacouna LNG receiving terminal.

The proposed terminal was the subject of a hearing by the Bureau d'audiences publiques sur l'environnement (BAPE). The BAPE issued its report late last year.

Note that this upcoming NEB hearing is not about the facilities that would be required to extend the natural gas system from St. Nicolas to Gros Cacouna. These would be the subject of a future application to be filed with the NEB by Gazoduc TQM, which we have not received yet.

Rabaska Lateral

Another potential project is an application that may be filed in respect of a lateral to connect to the proposed Rabaska LNG receiving terminal.

A hearing on the LNG terminal itself was recently conducted by the BAPE.

Emera Brunswick

All of the necessary approvals have been received on the Canaport LNG terminal in Saint John, N.B. Site preparation and construction have commenced.

The connecting pipeline facilities consist of 145 km of pipeline between Saint John and the M&NP pipeline in the U.S., at an estimated cost of $350 million. The NEB hearing was held in Saint John in November 2006. The matter is under deliberation.

Note that, for environmental assessment purposes, the hearing was a pilot project using the substitution provisions of the Canadian Environmental Assessment Act (CEAA). Pursuant to that Act, equivalent public review processes can substitute for an environmental assessment conducted by a Review panel under CEAA. The NEB process is one such process.

We hope that one day, substitution is the norm as opposed to only a pilot project. This would contribute to a more effective process overall, fully leveraging the broad and deep environmental and socio-economic expertise of the 30 or so NEB employees who specialize in environmental, socio-economic and land matters.

Deep Panuke

The application for the Deep Panuke project was filed by EnCana on 9 November 2006. It consists of offshore production facilities designed to develop natural gas resources adjacent to Sable island resources, and a pipeline connecting these facilities to the existing Maritimes and Northeast Pipeline, for a total estimated cost of over 700 million.

The application was filed jointly with the NEB and the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB). The CNSOPB is responsible for the production aspects. The NEB's role in the project is the connecting pipeline.

We have decided to integrate the CNSOPB and the NEB process into one. The coordinated hearing will begin in Halifax on 5 March 2007.

Keystone Project

Let us now switch to projects related to oil.

The Keystone project, recently filed with the NEB, is a proposed crude oil line that would run from Alberta to markets in Illinois. The proposed project involves the acquisition and conversion of 864 km of existing gas pipeline owned by TransCanada PipeLines to an oil transmission pipeline to be owned by TransCanada Keystone Pipeline. There would be also 371 km of new pipeline, pumps, tanks and related facilities in Canada. The project would have an initial capacity of approximately 435,000 b/d. The capital cost would be $664 million.

On 4 June 2007, the Board will begin its hearings into the facilities application.

Enbridge's Alberta Clipper and Southern Lights

Enbridge's Alberta Clipper Project involves the construction of a new 36-inch diameter 1590-kilometre crude line from Hardisty, Alberta to Superior, Wisconsin, primarily following Enbridge's existing right-of-way. The capital cost would be $US 2 billion. Initial capacity on Alberta Clipper would be 450,000 b/d, with ultimate capacity available of up to 800,000 b/d. To balance the increased capacity into Superior, an expansion of the 42-inch Southern Access line to Chicago would be undertaken at an estimated cost of approximately US.1 billion.

Enbridge's Southern Lights pipeline project is designed to bridge the gap between the available supply of light hydrocarbons (referred to as "diluents") from U.S. refineries and supply centres and increased demand for diluent by petroleum producers in the oil sands and heavy crude oil production regions in Western Canada. Diluents are light hydrocarbons that are used to dilute heavy crude oil and bitumen (a thick, tar-like form of oil found in the oil sands) to a consistency that is thin enough to be transported by pipeline.

Applications for both of these projects are expected to be filed with the NEB over the next few months.

TMX-2 TransMountain Expansion

Terasen Pipelines (also known as TransMountain) has a number of expansion scenarios, one of which is called TMX-2. With this project, Terasen would be adding 100,000 b/d of capacity to its system, which transports oil and oil products from Alberta to British Columbia. This would require 495 km of pipeline and associated facilities including new pump stations and storage tanks.

The company is pursuing commercial support for the project.

The NEB as a Partner

In its Strategic Plan, the NEB describes its vision as follows:

"The NEB is an active, effective and knowledgeable partner in the responsible development of Canada's energy sector for the benefit of Canadians."

There are many ways in which we propose to do that. As indicated in earlier examples, we are constantly searching for ways to make our regulatory process more efficient and effective. The substitution pilot project used in our review of the Emera Brunswick Project, and our joint hearing with the CSNOPB on the Deep Panuke project, are two examples of our determination in this regard.

Another example is seen in the consultations that are underway throughout Canada as we prepare for the release, in the fall of 2007, of our Energy Futures Report. Our team working on this report will be visiting Montreal on 9 March 2007, where they will be meeting for a second time representatives from industry, governments and non-governmental organizations, to further the analysis of three key scenarios of Canada's energy future. If you have not been involved in this process to date, and you would like to know what is going on and contribute to the analysis, you may do so by visiting Energy Futures Report index.

Your National Energy Board

My goal today was to provide you with an overview of hydrocarbons in particular and energy in general in our lives, and to illustrate by a few examples the infrastructure needs related to the supply and demand of energy. I also tried to outline the role of the NEB in the assessment of infrastructure projects in Canada and in Quebec, demonstrating that NEB matters are highly relevant to the members of Association Pipeline and to the people who attend your luncheons.

I hope that, as a result of this presentation, some of you will see in the NEB one of your public institution that is relevant and helpful to you in your personal or professional life.

We constantly look for opportunities to continually improve our processes, in partnership with others. We welcome your comments and suggestions, and we would be pleased to respond to your questions about energy. Please do visit our Web site (www.neb-one.gc.ca), and do not hesitate to contact us at 1-800-899-1265 (toll free).

Thank you for the opportunity provided to me today to be part of the energy dialogue in Quebec.