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Home > Speeches and Presentations > Speeches and Presentations 2008 > Meeting North American Gas Demand - Canadian Perspective

Meeting North American Gas Demand - Canadian Perspective

Presented by
Roland George
Board Member
National Energy Board

The Energy Council's 2008 Conference
Hoover, Alabama

7 June 2008

Meeting North American Gas Demand: Canadian Perspective

I wish to thank the Energy Council for inviting me to participate in this conference.

I am a Member of the National Energy Board of Canada, a public institution that will celebrate its 50^th anniversary next year.

I have been asked to speak about natural gas trends and developments in Canada and their impact on overall North American gas demand. During the presentation I will refer to some official Board reports, but the comments I provide today are my own.

Canada's Energy Resources

Canada is rich in energy resources and it is vital that these resources be managed responsibly and safely. Canada is also the largest, most secure and reliable energy exporter to the U.S.

Including the oil sands, Canada's oil reserves are second only to Saudi Arabia. Canadian oil production is projected to grow from about 2.7 million barrels per day in 2007 to 3.5 million barrels per day in 2015.

Canada's total natural gas exports for 2007 were about 10.4 Bcf/d (9.1 Bcf/d in terms of net exports). We are exporting more than half of our production. From a US standpoint, Canadian natural gas represents 15% of American natural gas requirements. Canada's gas export markets are the U.S. Central/Midwest, Northeast, and California/Pacific NW (41, 34 and 24 percent of 2007 exports, respectively).

In 2007, the energy industry accounted for almost 6 percent of Canada's gross domestic product and $90 billion of our total exports. In real terms, energy accounts for about 20 percent of the total value of Canadian exports. Last year the energy industry spent almost $69 billion in Canada or about 35 percent of total private sector investment in this country.

For these resources to be provided to the marketplace, Canada needs infrastructure such as pipelines and electric power lines.

Energy Roles - Regulatory

The NEB is Canada's federal energy regulator. We regulate interprovincial and international pipelines, international power lines, energy exports, gas imports, and oil and gas activities on non-accord frontier lands and offshore areas, as well as other related responsibilities.

In terms comparable to the U.S., the NEB combines responsibilities of the Federal Energy Regulatory Commission, with many of those of the US Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Energy Information Administration.

As the federal regulator, our vision is to be an active, effective and knowledgeable partner in the responsible development of Canada's energy sector for the benefit of Canadians. The NEB strives for excellence in regulatory leadership and accountability.

Natural Resources Canada is the government's primary source of energy policy advice. The NEB takes government energy policies into account when carrying out its regulatory functions.

Most provinces and territories have energy regulating bodies with specific mandates and responsibilities for their jurisdiction. Provinces own their natural resources and have their own regulators for resource conservation and intra-provincial electricity transmission.

The NEB works with a number of provincial and federal agencies to share best practices and to improve the regulatory process.

Canada's Energy Future - Reference Case & Scenarios

The National Energy Board has a mandate to monitor the outlook of energy supply and demand in Canadian markets and provide Canadians with energy information. This is the purpose of the report on Canada's Energy Future.

Last November, the Board released a comprehensive report of Canada's energy supply and demand outlook for the years 2005 to 2030. We have been conducting these studies since 1967 on roughly a four year frequency. The current edition, consist of a reference case analysis from 2005-2015 and an analysis of three scenarios, which extend out to the year 2030.

In order to understand our results, it is important to have an appreciation of the assumptions in terms of the energy prices and economic conditions which underlie the reference case and each of the scenarios.

The Reference Case is our best guess about the development of supply and demand in Canada based upon current decisions and policies and current economic and energy trends. It is characterized by moderate energy prices and business as usual developments. For example, natural gas prices are assumed to follow a traditional relationship with crude oil. (84% of the 6:1 Btu parity)

The scenarios are intended to address uncertainty. Uncertainty which is caused by world geopolitical and economic factors, social trends, future policy decisions, or technology developments. Each scenario is based upon a set of internally consistent assumptions, designed to test our findings. We see each scenario as plausible and don't attach a probability to the scenario.

Continuing Trends extends trends used in the reference case out another 15 years to 2030.

Triple E scenario assumes fairly aggressive conservation goals pursued on a global level. The scenario has more moderate economic growth as a result of economic/environmental trade-offs. There is a preference given to greener fuels such as renewables, nuclear and natural gas and some form of carbon pricing is assumed. By 2030, this scenario has the lowest energy prices from a producer perspective. This is achieved through a cooperative global environment resulting in abundant energy supplies around the world, as well as comprehensive energy demand management programs, which slow energy demand growth.

The Fortified Islands scenario focuses on North American energy security. It has the slowest economic growth and highest energy prices. These outcomes are a result of a security conscious world, where continued geopolitical tensions limit access to cheap global energy supplies. The emphasis is on developing indigenous energy sources. \

Again, these scenario storylines were developed through extensive discussion with energy experts both at NEB and outside. These were further refined during the cross-Canada consultation sessions.

Natural Gas Resource Utilization

Canada has a large remaining resource base of natural gas (dark columns) under any of our 3 Energy Future scenarios

The amount of resource that would be produced between 2005 and 2030 is shown adjacent to these columns.

Over the period, production continues to rely heavily on the conventional resource in western Canada and on the unconventional tight gas resource. Conventional gas from western Canada is still the largest component of supply, but is in decline in all scenarios. There remains a large amount of conventional resources (134 Tcf). But on average, new conventional gas wells are less productive than those discovered previously so have less output for the same amount of drilling effort and cost.

CBM has an increasing role, especially at higher prices, peaking at 1.6 Bcf/d in the middle and low cases and 3.5 Bcf/d in the high.

This analysis was fairly conservative regarding shale gas in estimating about 1 percent of production in the Continuing Trends and Triple E scenarios. Shale gas does better in Fortified Islands to account for about 4 percent

CBM has an increasing role, especially at higher prices, peaking at 1.6 Bcf/d in the middle and low cases and 3.5 Bcf/d in tOther unconventional and frontier resources are challenged by uncertainty and the lengthy time and high costs for the infrastructure needed to connect to their remote locations. Through 2011, frontier production is from the east coast only. Mackenzie gas is assumed to become available in 2014 in Continuing Trends and Fortified Islands. Whether this actually happens is subject to the regulatory process underway, and corporate decisions and timing that might result. By 2017, oil production from the existing projects off Newfoundland is done and you can access the associated gas. In Fortified Islands we include offshore Labrador, and the western Arctic

As a result, Canadian gas production declines in 2 of our 3 scenarios. At the same time, the scenarios call for Canadian gas demand to grow. One of the key areas of demand growth is to fuel oil sands operations.

Canadian Gas Production

In the Reference Case, production is relatively flat though 2010 followed by a gradual decline. Coal bed methane (CBM) production reaches 2 Bcf/d by 2015. On the frontiers, Deep Panuke is assumed to enter production in 2010, with Mackenzie starting in 2014.

In the Continuing Trends scenario, existing declines in western Canada continue. Domestic gas supply gradually declines by almost half over the period.

LNG projects in Atlantic Canada, Quebec and British Columbia are at various stages of consideration. LNG imports are projected to begin in 2009 at 0.5 Bcf/d and ramp up as additional terminals are constructed and utilization increases. By 2015, three terminals are assumed to be operational and importing 1.4 Bcf/d on an annual basis. In Continuing Trends, a fourth terminal is added and utilization rises to stabilize at just over 2 Bcf/d.

In Triple E, abundant LNG imports drive gas prices down. Imports of LNG in Triple E are more than double that in the Continuing Trends Scenario. By 2021 LNG imports would stabilize at 4.8 Tcf/year through an estimated 7 terminals operating at 70 to 80 percent utilization. By 2030, LNG imports would be equivalent to roughly 95 percent of Canadian domestic gas production. Domestic gas production slows as some of the higher cost conventional and unconventional resources are uneconomic.

In Fortified Islands, higher prices enable strong Canadian gas supply. Extensive development of unconventional and frontier sources occurs. An unstable international investment climate and reduced international trade would require North American gas markets to be largely self sufficient, with only minor amounts of LNG imports (none entering through Canada after 2015).

Canadian Net Gas Exports

Canadian gas demand increases steadily through 2015 largely due to increasing gas use for oil sands and electricity generation

After 2015, gas demand is highest in the Continuing Trends scenario due to strong economic growth. Gas demand growth is lower in Triple E due to high environmental standards and improved efficiency and lowest in Fortified Islands because of higher prices and slower economic growth.

With Canadian gas demand increasing in all cases, and flat to declining Canadian production in the Reference, Continuing Trends and Triple E, it results in a significant tightening of the supply-demand balance.

The difference between domestic supply and demand is indicated here as potential net gas exports. Note that imports for re-export of LNG, Lower 48 and Alaskan gas are not included and that these volumes would serve to supplement pipeline throughputs including export pipes. Any reduction in net gas exports from Canada is expected to be offset by increased U.S. production and greater imports of LNG into the U.S.

In Fortified Islands, net gas exports are above current levels for most of the period as frontier developments in Canada's north and off the east coast and Labrador enter service.

Canadian Natural Gas Wildcards

Subsequent to the analysis in the Energy Future project, industry sentiment regarding gas drilling in western Canada, and Alberta in particular, turned considerably more negative. Industry concerns over cost escalation, better oil economics, and changes to Alberta's royalties caused gas investments to be scaled back. Western Canadian gas drilling has always been very responsive to price. For much of this decade it appeared that a price in Alberta of around $7/mmBtu would sustain gas drilling at levels that kept deliverability fairly stable. When price went below $7, activity slowed, and when price went above $7, activity picked up. For much of 2007, $7 wouldn't bring back the average level of activity. It may be that cost inflation and declining gas well productivity is pushing this threshold price closer to $9. With Alberta prices moving back toward that range, we see the potential for gas drilling to pick up in the second half of the year, provided that the labour is available to operate the rigs, and that returns are not higher in other jurisdictions.

Through 2007, global LNG has been in relatively short supply with Asian and European markets readily outbidding North America for spare cargoes during peak demand periods.

Pipeline projects to access gas in the Mackenzie Delta and Alaska have been around for decades. TCPL was selected under Alaska's Gas Inducement Act to proceed to an open season and receive some financial backing for the regulatory process. How this might impact the Mackenzie Gas Pipeline project remains to be seen

On the demand side, there is considerable uncertainty regarding the key oil sands market. Roughly ¾ of the resource is too deep to surface mine and instead must be heated underground to be able to flow to horizontal wells. Although more energy intensive, there is also the possibility of substituting alternative fuels with a number of different technologies being evaluated

Finally, gas-fired power. There are few alternatives to the operational flexibility, ease of siting, rapid construction, and low initial capital costs associated with gas-fired facilities. This is particularly the case if the power grid requires a backup source of power be at a site close to a remote wind facility. Clean coal may yet supplant future incremental gas additions, but uncertain costs for new technology and future emissions has slowed its application.

Total Canada Deliverability Projection

Looking at natural gas from a more short term perspective, this figure shows our reference case projection of Canadian gas production from last fall, and actual output derived in a couple of ways.

The black line is the most authoritative, showing measured production from the individual wells.

The blue dots are based on measurement of gas entering the pipelines and provide a more real-time indication that is still fairly accurate.

You see Canadian production has been generally about 1 Bcf/d lower than last year and despite some recent trending above our reference case projection, the slow down in drilling will likely return the actual trend toward our projection.

Yet, recent price increases and announcements of greater activity in western Canada indicate that an increase in 2009 is possible (as indicated earlier production is quite sensitive to price) .

And the next few slides will show a few more potentially positive developments in terms of Canadian natural gas supply.

Shale Gas in Canada

Despite the declines in Canadian gas production, there have been several positive announcements of early exploration results from shale gas plays across Canada. Shale gas represents a potentially huge resource, possibly comparable to the size of Canada's conventional gas reserves.

These announcements should be regarded with caution due to the very limited exploration results achieved to date. It may be several years before enough drilling and assessment has been completed to determine to what extent Canada's shale gas may be commercially recoverable. In other words, shale gas areas may contain massive amounts of gas in-place, but having sufficient concentration and adequate permeability will be key to commerciality.

In the Horn River basin, another emerging play in a remote winter-only area just south of the Yukon border, company announcements suggest the play could have an estimated potential resource of 18 to 28 Tcf. The Upper Devonian Muskwa and Klu shales are found at depths of 7500 to 9000 ft, are up to 580 ft thick and have been described as "extremely charged" with natural gas (up to 2.5 x Barnett).

The Montney is not really a shale gas play but has been described as a "turbidated dirty, sandy, shaley hodgepodge of everything" and, although deeper, is very similar to the shallow Milk River play in southeast Alberta that has been a mainstay of Canadian production for many decades.

Forest Oil of Denver plans to drill three horizontal wells this year in the Utica shale in Quebec's St. Lawrence Lowlands (two prospective horizons, averages 500 ft thick at 2,300-6,000 ft.)

Canadian Shale Gas Operations

In order to qualify these Canadian shale gas plays, companies have indicated that they compare favorably with the Barnett Shale in Texas. That is in terms of shale thickness, gas content and rock properties.

However, since the Horn River shale formation is in a remote northern location, drilling is only possible in the winter. This winter-only access and the need for more infrastructure, including roads, processing facilities and pipelines, will slow development. There is also a significant difference in the ability to drill tightly spaced wells when one compares Barnett wells on the bald prairie near Fort Worth TX to wells in northeast B.C. that must be cut out of the bush. This photo showing the hydraulic fracturing of a well in northeast B.C. indicates how intensive this type of operation is.

Wells in the Horn River Basin could cost $6 to $10 million compared to the Barnett at around $3 million. Montney wells cost somewhat less at an estimated $3 million to $5 million. Corporate announcements indicate Horn River and Montney wells are expected to recover about the same amount of gas as Barnett wells - about 4 Bcf/well.

Mackenzie Gas Pipeline

I can't say much about the Mackenzie Gas Project because the proceedings are ongoing. As reported on May 6th (Daily Oil Bulletin) the latest on the Joint Review Panel (JRP) report is that it is not expected to be completed in 2008.

Beyond that, I will simply refer to the NEB Panel's concluding remarks in Yellowknife in September 2007:

We will receive and consider the Joint Review Panel report responsible for the environmental and socio-economic assessment of the project.
We will receive and consider the government's response to that report. We will hear final argument.
We expect to be convening for final argument about 4 months after receipt of the Joint Review Panel report.

The executive director of the Northern Gas Project Secretariat indicated in May that the delay in the release of the JRP report, necessary before the National Energy Board can convene for final arguments, will likely push into 2010 other regulatory approvals such as water licence and land use permits.

Alaska Gas Pipeline

I'd also like to include some discussion of the proposed Alaska Gas Pipeline.

Canada is ready to deal with any application, whether it is applied for under the Northern Pipeline Act or the National Energy Board Act. A regulator can best meet the challenge by maintaining a constant state of readiness for the possible applications that may be filed. This means, in practice, that our staff stays in touch with people in the energy sector, and Board members stay abreast, through the information provided by our staff and through their own research of energy developments.

This project has a long history. In 1976 and 1977, the NEB held a hearing on northern gas pipeline applications that sat for 214 days. The Board's decision favoured the Foothills Pipeline proposal for a pipeline to transport gas from Alaska through the Yukon along the Alaska Highway, then south through British Columbia and Alberta and into the US Lower 48.

In September 1977, an agreement between Canada and the U.S. was signed which committed both countries to the construction of a pipeline from Alaska and northern Canada.

In April 1978, Royal Assent was given to the Northern Pipeline Act. The Act declared that certificates of public convenience and necessity were issued and deemed to be NEB certificates for the Foothills group of companies. The Act also authorized the establishment of the Northern Pipeline Agency to oversee the planning and construction of the Canadian section of the project.

Between 1980 and 1982, the western and eastern legs of the pre-build were constructed. During this period, the Northern Pipeline Agency grew to approximately 135 employees, located in Ottawa, Calgary and Whitehorse. The northern portion of the pipeline was originally intended to be completed immediately after the pre-build. However market circumstances changed. Demand for natural gas in the U.S. declined, interest rates and inflation rose, and the northern portion was never built. Northern Pipeline Agency staff returned to their original organizations, including the NEB.

Fast forward to January 2008, when the Alaska Governor and her Gas Team announced that a proposal from TransCanada/Foothills Pipelines for the Alaska portion of a pipeline has met the requirements of the Alaska Gas Inducement Act. TransCanada/Foothills Pipelines has retained the original certificates issued under the Northern Pipeline Act. Some of the other proposals that had surfaced prior to the Alaska Gas Inducement Act process had raised the prospect of filing an application under the National Energy Board Act.

"The Future is Bright" or is it "May Your Life Be Interesting"

Canada is and will likely remain the largest, most secure and reliable energy exporter to the US and that includes natural gas.

Conventional production from western Canada may be declining but CBM, tight gas, shale gas, northern gas, offshore and other gas resources are quite large and could be developed depending on prices, costs and technology.

Alaska gas and LNG transiting through Canada on its way to the Lower 48 could supplement this Canadian production.

Therefore, Canada's export pipelines will likely continue to deliver substantial volumes of gas for many more decades (of course, this is said without prejudging the merits of any specific future export application).

Thank You!

If you are interested in knowing more about the topics I discussed today, you can talk to me, or: