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Home > Speeches and Presentations > Speeches and Presentations 2009 > Canadian Energy Market Dynamics

Canadian Energy Market Dynamics

Presented by
Sheila Leggett
Vice-Chair
National Energy Board

IAGT Symposium
Banff, Alberta

21 October 2009

I wish to thank the Industrial Application of Gas Turbines (IAGT) Committee for inviting me to participate in this symposium.

The National Energy Board of Canada is a public institution that is celebrating its 50^th anniversary this year.

I am planning to talk about some of the changes and challenges that are happening in energy maprkets in Canada.

During the presentation I will refer to some official Board reports, but the comments I provide today are my own.

Natural Gas-Fired Power

This symposium is working on how to get the greatest efficiency, reliability and lowest emissions from gas turbines.

Given the growing role of gas-fired power generation, and ongoing role in industrial and pipeline compression, this work is critical for Canada in terms of the configuration of our energy systems, energy costs and our climate priorities.

Drivers such as economic growth, lifestyle choices, and energy costs help to determine the size and shape of the power load.

Factors such as reliability requirements, renewable energy targets, fuel diversification objectives, and siting and grid limitations help determine how much of that load will be met by gas-fired generating capacity.

The efforts of those in this room help to determine how many units will be required, what size, how much they will cost, and how much they will operate

The efforts of the natural gas industry - producers, pipelines, distribution companies, consumers and regulators helps to determine where natural gas can be accessed to run them, how efficient the transportation system is to get the gas there, and how much it costs to produce and transport that fuel.

Canada's Energy Resources

Canada is rich in energy resources and it is vital that these resources are managed responsibly and safely.

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 2008 to 3.8 million barrels per day in 2020.

Net natural gas exports for 2008 were about 8.5 Bcf/d. We are exporting more than half of our production. From a US standpoint, Canadian natural gas represents 14 per cent of American natural gas requirements. Canada's largest natural gas export markets are the U.S. Central/Midwest and Northeast regions.

In 2008, electricity exports reached record highs as high water levels resulted in abundant hydro-electricity.

In 2008, the energy industry accounted for seven per cent of Canada's gross domestic product and $133 billion of our total exports. In real terms, energy accounts for about 28 percent of the total value of Canadian exports. The oil and gas industry in Canada spent $44 billion in 2008.

Lots of Large Moving Pieces

There has always been uncertainty in energy markets.

But in the 1990's it seemed like uncertainty was measured in 100-200 MMcf/d increments of natural gas and 50,000 bbl increments of oil.

Now the game seems to involve much bigger pieces:

Oil sands projects involve tens of billions of dollars in investment per year, but have seen an estimated $200 billion of projects delayed or put on hold since mid-2008. At some point, these may come roaring back to life.
A potentially huge oil discovery estimated at perhaps 50 to 70 billion barrels has been made in the deep water off Brazil.
Mexican and Venezuelan oil production has declined by about 24 per cent or -1.7 million barrels per day in the last four years (a decline equivalent to about half of Canada's total crude oil production).
LNG supply is expected to expand by about 20 per cent or 5 Bcf/d over the 2009 to 2010 period as new projects enter service. This is occurring at the same time that economic conditions have caused global demand to drop. Few new LNG projects have been sanctioned since. This creates some risk that when global demand eventually recovers, the apparent surplus of LNG could be absorbed quickly.
Shale gas - reservoirs with such poor flow characteristics that they were bypassed for decades are now being tapped through technological advances in fracturing the rock. A recent estimate indicates shale gas may increase U.S. reserves by 35 per cent - Canada has shale gas in various locations across the country that is in the early stages of development. That is just North America; many countries around the world have shale and could potentially have shale gas.
Natural gas pipelines from the north are huge, capital intensive projects with long lead times. Yet two of the key factors required for their economic evaluation - steel costs and natural gas prices - have been rising and falling by stunning amounts.
This price and cost volatility is likely to be an ongoing feature of energy markets. Since, just like an elephant, major projects that have sufficient scale to make meaningful contributions to supply or demand take a while to get started, and once in motion are difficult to stop or change direction through some form of reconfiguration or downsizing. So as the ponderous mass of large scale energy projects attempts to meet up with the bouncing ball of prices and costs, there could be plenty of undershooting and overstepping the exact capacity required at a specific time.

Gas and Oil Pipelines in Canada and in the United States

The NEB gets involved with many of the big energy pieces in motion in Canada.

Like natural gas was in the 90's, oil infrastructure has been the main regulatory activity at the Board over the last 5 years. Major oil pipeline expansions within Canada are being driven by oil sands expansion.

Future developments could include: oil to the west coast to access new Asia markets and development of the Bakken oil play in Saskatchewan and North Dakota.

Over the last five years or so, The Board has also been active on major natural gas infrastructure with:

The offshore, through the Deep Panuke project where first gas may be flowing late next year;
The LNG industry, through Emera's Brunswick Pipeline connecting to the first LNG import terminal in Canada, along with decisions on import and export licences;
Applications for pipeline infrastructure in the shale and tight gas areas of Northeast B.C.;
Natural gas pipelines from the north;
Board's jurisdiction of NGTL adds 24,000km of pipe;
Possibility of an application to export natural gas as LNG via a potential terminal on the west coast and a connecting pipeline from the supply area in western Canada.

There is also the prospect of major CO2 pipelines that cross interprovincial or international borders as part of carbon capture and storage, or enhanced oil recovery projects.

Of keen importance to the Board is a focus on sustainability. This means that we will continue to take into account, together, the economic, social and environmental dimensions of the matters being considered when we make a decision.

NEB Areas of Responsibility

The National Energy Board has as part of its mandate, the responsibility to:

Monitor energy markets;
Provide advice to the federal government;
Issue reports on energy issues to inform the Canadian public.

It is under this mandate that I will be describing some of our views of future energy markets.

Canada's Energy Future and 2009 Reference Case Scenario

If you ever find you need energy projections to compare against your planning projections, there are several prime candidates available at no cost on the NEB website

The report on the left is our Energy Future report that projects Canadian energy supply and demand to 2030.

This report is the Board's flagship report and is issued every four years.

The latest one was released in November 2007 and provides three complete scenarios plus a reference case that describe all forms of energy in Canada.

The report on the right is an update to the first report.

It was released in July of this year and updates the Reference Case from the first report over the period to 2020.

It includes low and high energy price cases rather than scenarios.

Key drivers for the Reference Case Outlook are energy prices, economic outlook and government policies.

See Energy Futures

Crude Oil & Natural Gas Prices

This chart provides the price outlook for crude oil and natural gas from our Energy Futures Reference Case Update.

The price of West Texas Intermediate (WTI) crude oil at Cushing OK is indicated in red and NYMEX natural gas at the Henry Hub is shown in blue. The scales on the sides are adjusted for the energy equivalence of the two fuels (6:1).

Natural gas and crude oil prices maintained a relationship throughout much of the last decade and the first half of this decade with natural gas at a slight discount to crude oil on an energy equivalent basis (average was 8:1 when energy equivalency is 6:1).

Since 2005, the price ratio has averaged 10:1.

In 2009 as crude oil prices began to rally while natural gas prices have continued to soften, the price ratio has widened toward 20:1.

The dramatic widening of the price ratio between crude oil and natural gas reflects the increased use of oil as a financial instrument and differences in perceptions between the global market for crude oil and the continental market for North American natural gas. While both oil and gas markets exhibit signs of excess supply relative to demand (oil markets with high inventories measured in days of forward cover, North American natural gas markets in high levels of underground storage), global oil markets are more diversified and can respond to a wider variety of signals (such as economic recovery in China) than the more narrowly focused North American natural gas market that is largely dependent on a U.S. recovery.

Natural Gas Supply Outlook

Natural gas supply outlook reflects drilling and the shift to more tight gas and shale gas.

Tight gas and shale gas is natural gas found in low permeability formations that does not readily flow to the well bore without external stimulation of the reservoir.

Montney tight gas and Horn River shale gas offset declines in other Canadian gas sources after 2010 in the Reference Case, and create incremental growth in the High Case. In the Low Case, tight gas and shale make key contributions to supply, but are not enough to stem the decline in other Canadian gas sources.

Current market conditions would most closely resemble the Low Case.

Canadian Natural Gas Deliverability

Nearer term, the lack of drilling activity in western Canada in 2009 and into 2010 could result in a deeper trough in natural gas production than was previously anticipated in our long term outlook.

This projection comes from our latest deliverability outlook and suggests a 2.7 Bcf/d drop in output between 2008 and 2011.

By sometime in 2010, the drop in North American natural gas output should begin to match the fall-off in natural gas demand and start to rebalance the market.

That market balancing could lead to higher prices that may support additional drilling and begin to slow or possibly begin to reverse declines in 2011.

Standard Well Completion

One of the key drivers for the stabilization of future natural gas production is a switch to tight gas and shale gas resources.

This shift to tight gas and shale gas makes a big difference in the way wells are completed.

For a standard vertical well, the operator would drill the well, insert steel casing and cement the casing in place to maintain the well integrity. Then at the desired depth, the operator would set off a charge to perforate the casing so the gas could flow into the well. Flow lines are installed and the well can go on production.

Well Completion - Unconventional

For a tight gas or shale gas well, the completion stage can be as costly as the drilling

This type of hydraulic fracturing operation is where you pump huge volumes of a fluid or gas at high pressure to crack the rock open. This fracturing is done under control so that the cracks only impact the gas bearing formation and do not extend to the surface or to potable ground water zones. Along with the fluid, a granular material such as sand or tiny ceramic beads is injected to remain in the reservoir and help hold the cracks open.

This is the technological game-changer that is allowing formerly uneconomic reservoirs to become economic, and in some cases to even become low cost production areas.

But you can see the level of capital and human effort that is required.

This is the approach used to access tight gas and shale gas resources, which are likely to eventually dominate overall production as other resources continue to decline.

Crude Oil and Bitumen Production

Oil production is expected to offset ongoing declines in conventional light and heavy crude oil production with unconventional oil. Unconventional oil is oils sands production.

By the end of the outlook period, Canadian crude oil production is projected to reach 3.75 Bcf/d.

By 2020, expectations are that slightly more oil sands production will be upgraded into synthetic crude oil, than would leave western Canada as non-upgraded bitumen.

Conventional oil production in western Canada has been in decline since the 1970's. Conventional oil production off Newfoundland may postpone some of the decline in eastern Canada production shown here if extensions to the producing fields and additional satellite fields are brought into production.

Electricity Generation Capacity Outlook

Our outlook for electricity generation capacity increases by 21 per cent between 2008 and 2020.

Nuclear, natural gas and hydroelectric capacity are all expected to increase.

Emerging sources: wind, biomass, solar, tidal, and small hydro are projected to grow rapidly, but because they start from such a small base, their share of overall capacity remains small.

Installed coal capacity is projected to be almost cut in half with the retirement of Ontario's coal-fired generating plants and decreases in Alberta, Saskatchewan and Nova Scotia.

Hydroelectric capacity will continue to be the major source of electricity although its share decreases slightly from 58 per cent to 53 per cent of Canadian generating capacity.

Our Reference Case assumes extensive development of new hydro projects in Quebec, and Labrador including the Lower Churchill facility in Labrador (2 260 MW) and the Eastmain River diversion and the Romaine generating station in Quebec (2 441 MW).

Total nuclear capacity could also increase by 24 per cent. We assumed nuclear additions in New Brunswick (680 MW in 2017) and Alberta (1 000 MW in 2020) and refurbishment or replacement of the facilities in Ontario, Quebec and New Brunswick.

Natural gas will continue to be relied on to meet increased electricity demand. Natural gas-fired generation is forecast to increase during the period of the Reference Case by an additional 5 517 MW of combined-cycle generation, 2 629 MW of combustion turbine/cogeneration facilities, and a decrease of 1 243 MW of the less efficient steam turbine generation. In the near term, investment in combined-cycle generation is planned for Ontario as well as Newfoundland and Labrador. In Ontario, combined-cycle gas will be relied on to help meet demand following the phase out of coal-fired generation.

Installed unconventional "emerging technologies" generation remains small relative to the more centralized conventional sources, but large changes are expected to occur. Wind power is projected to experience exceptionally strong growth from 2 400 MW in 2008 to 16 400 MW by 2020. The largest volume of wind power additions could occur in Quebec (5 885 MW), Ontario (3 280 MW), Manitoba (1 200 MW) and Alberta (1 522 MW).

Other generation technologies, such as biomass, landfill gas, waste heat, solar and tidal could grow to 3750 MW.

Electricity Generation Outlook

Conventional generation is expected to provide the majority of energy throughout Reference Case timeline.

Natural gas-fired generation output is forecast to increase from 50 809 GW.h to 82 670 GW.h in 2020, or from 8.4 per cent to 11.2 per cent of total electricity generation.

Nuclear generation output is also forecast to increase.

Generation from coal could drop 45 per cent.

Alternative and emerging technologies could begin to gain share in the Canadian generation mix, especially from wind where output shows a significant increase from 4 900 GW.h in 2008 to 32 000 GW.h by 2020.

Electricity Demand

Our projections may fail to capture the full extent of the reduction in industrial electricity and natural gas demand in 2009 due to the recession.

The extent and pace of a potential recovery or possible growth of industrial energy demand is difficult to ascertain. Key demand sectors are the production of oil sands in Western Canada and Ontario's manufacturing sector.

A stronger push for energy efficiency may result from the combined impact of objectives to reduce emissions and in response to price volatility.

Natural gas-fired power is often a preferred alternative when electricity demand growth is uncertain. Natural gas fired generating facilities can generally be constructed in smaller increments and with less lead time than other forms of generation which can reduce the investment risk.

Energy Demand Management and Environmental Programs and Policies

One of the biggest challenges in projecting energy demand is the implementation of several key policies at the federal level. These policies are continuing through the development stage.

Expectations are that these policies will influence the absolute level of energy demand as well as the fuel mix. Changes in the absolute level of energy demand will depend on the sector and sub-sectors considered. Policies designed to improve energy efficiency, such as vehicle efficiency standards, will reduce energy demand.

The full benefit of these improvements in energy efficiency might not materialize due to a rebound effect. The rebound effect means the tendency for consumers to increase utilization of energy-using devices when efficiency improves due to reduced operational costs (e.g., increase travel due to improved vehicle efficiency).

Some technological solutions to reduce GHG emissions, such as carbon capture and storage can increase energy demand requirements together with the reduction of GHG emissions as additional fuel is required to capture, transport and store CO₂.

There is likely to be very little fuel switching over the period to 2020. Changes in fuel demand are slow to occur, in large part due to the large number of existing energy-using devices in the economy. However, upcoming legislation could encourage faster development and/or adoption of alternative and renewable fuels resulting in higher consumption of these fuels and reduced demand for more conventional fuels than presented in this analysis.

Backup for Wind Power

Natural gas-fired power may also be preferred as a backup to intermittent wind power. Natural gas-fired units can generally be brought on line quickly to supplement the variable nature of wind power output. Natural gas units may also have greater siting flexibility that may allow better coordination with electricity grids designed to access remote wind power locations.

Due to their smaller scale and lower emissions, natural gas-fired power generating units also tend to be more acceptable than other forms of generation in locations close to markets. This can reduce the required length of high voltage transmission lines which can lower capital costs, reduce line losses and reduce stakeholder opposition.

One challenge may be that if the wind output is highly intermittent, the backup gas-fired units may be combustion turbine units and not the more efficient combined cycle units.

Under such conditions is it possible that natural gas consumption and emissions would be higher than if the entire wind output were replaced by combined cycle gas units?

Pipeline Operations

Natural gas-fired electricity generation is welcomed as a growth opportunity for natural gas shippers.

However, the greater the load and the extent that it swings up and down in a relatively short period of time can have significant consequences for the operation of a natural gas pipeline.

Adequate line pack volumes and access to natural gas storage must be considerations in system design when there is significant natural gas-fired peaking capacity on the system.

Emissions - CCS

The operation of CCS technology is likely to be an energy intensive process and by some estimates, could end up de-rating generating plant capacity by 20 to 30 per cent.

Based on conceptual designs for CO₂ capture facilities in North America, there are estimates that natural gas purchases could account for 60 per cent of the cash operating costs for CO₂ capture, compression and transportation while electricity would account for 16 per cent.

In other words, energy consumption would account for 76 per cent of the cash operating costs with the biggest energy requirement being the actual CO₂ capture, followed by compression.

Siting

Most of the Board's work is with pipelines - but public interest issues are similar for electricity transmission.

Interest in an East-West power grid and in major hydro-electric projects in remote locations like northern Manitoba and Labrador suggest the likelihood of many additional miles of high voltage transmission lines.

Access to regions with high wind potential may also require long transmission corridors.

Local opposition to transmission projects has been growing.

Difficulty in siting new transmission lines tends to favor gas turbines that can be sited close to markets.

Conclusion

Canadians can expect energy markets to function well with supply available to meet demand. Energy prices will provide appropriate market signals for the development of adequate energy resources to meet Canadian and export demand. Our outlook suggests that a large proportion of Canadian demand for energy will be met by fossil fuels over our forecast period to 2030.

Within the broader trends, there are some notable shifts. Energy demand is likely to grow at a slower pace, and combined with a move towards greener fuels, could result in slowing GHG emissions growth. There is also a significant shift towards unconventional production of oil and gas. Penetration of unconventional and "greener" technologies could also rise notably in the electricity generation sector.

We also recognize the growing interconnections between energy, environment and economy. This implies that environment and economy will provide an increasingly influential context to energy decisions. These considerations may lead to some fundamental shifts in how energy is consumed and produced in Canada and globally. In Canada, interest in environmental goals continues to evolve. Numerous federal and provincial policies aimed at sustainability, energy efficiency and limiting GHG emissions have been advanced. The extent and schedule of climate change measures varies significantly by province, but the notable development is that all provinces now have some mix of energy efficiency and climate change initiatives. As these initiatives are crystallized, they will influence the results of future energy demand and supply.

Thank You!

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