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Home > Speeches and Presentations > Speeches and Presentations 2009 > Unconventional Gas: Challenges for Pipelines and Markets

Unconventional Gas: Challenges for Pipelines and Markets

Presented by
Lyne Mercier
Board Member
National Energy Board

Conférence APGQ

18 October 2009

I wish to thank the Association pétrolière et gazière du Québec (APGQ) for inviting me to participate in this important event.

I am a Board Member of the National Energy Board of Canada, a federal quasi judicial tribunal that is celebrating its 50^th anniversary this year.

I am planning to talk about some of the changes that are happening in energy markets in Canada and the United States. I'm going to lay out some of the challenges present in energy markets today, and then turn things over to the rest of you smart people in the room to come up with solutions.

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 are managed responsibly and safely. Let's take a step back and look at a few significant statistics.

Canada's Energy Resources

Including the oil sands, Canada's oil reserves are second only to Saudi Arabia. Canadian oil production, conventional and unconventional, is projected to grow from about 2.7 million barrels per day in 2008 to 3.5 million barrels per day in 2015. This is in stark contrast to the state of the natural gas industry, as I will discuss later.

Net natural gas exports for 2008 were about 10 Bcf/d, although that has declined to less than 9 Bcf/d in the first half of 2009. Still, we are exporting more than half of our production. From a US standpoint, Canadian natural gas represents 16% of American natural gas requirements. Canada's largest export markets are the U.S. Central/Midwest and Northeast regions. Thus, from a supply perspective, issues in US markets invariably impact Canadian energy suppliers.

In 2008, the energy industry - oil, gas, and electricity - accounted for almost 7 per cent of Canada's gross domestic product and employed 363,000 people across Canada. Furthermore, energy exports in 2008 rose to $133 billion on the back of what were strong commodity prices, about 28 per cent of the total value of Canadian exports.

Lots of Large Moving Pieces

There has always been uncertainty in energy markets.

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

• The oil sands sees tens of billions of dollars of investment per year. China also now has claimed their own stake in oil sands development with their recent purchase of Athabasca Oil Sands Corporation.
• Potentially huge oil discoveries are being made in the deep water off Brazil.
• Mexican and Venezuelan oil production has declined by about 24 per cent in the last four years.
• 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. When global demand eventually recovers, a supply surplus of LNG may quickly turn into a deficit, and the long lead time required for project development means there may be a gap to be filled.
• Shale gas - as everybody in this room very well knows - comes from reservoirs with such poor flow characteristics that they were bypassed for decades are now being tapped largely because of advances in technology. A recent estimate has increased US natural gas reserves by 35 per cent from just two years ago. Canada is also fortunate to have shale gas potential in various locations across the country that are in the early stages of experimentation and development. That is just North America, many countries around the world have shale and could potentially have shale gas resources. Poland is expected to see its first shale gas well sometime in early 2010.
• 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.
• Price and cost volatility are likely to be an ongoing feature of energy markets. Since, just like an elephant, major projects that can make meaningful contributions to supply or demand take a while to get started, and once in motion are difficult to stop or change direction. So as the ponderous mass of energy projects attempts to meet up with the bouncing ball of prices and costs, there may be plenty of undershooting and overstepping the exact capacity required at a specific time.

Gas and Oil Pipelines

So how does the NEB fit into all of this?

Part of the NEB's mandate is to regulate pipelines and electricity-transmission lines that cross provincial or international borders.

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 expansions to the south are being driven by oil sands expansion.

However, over the last five years or so, the Board has nevertheless been active on major natural gas infrastructure with:

1. The LNG industry, through Emera's Brunswick Pipeline connecting to the first LNG import terminal in Canada, along with decisions on import and export licenses;
2. A recent ruling over NGTL, which grants the Board jurisdiction over an additional 24,000 km of pipe;
3. The offshore, through the Deep Panuke project where first gas may be flowing late next year;
4. Applications for pipeline infrastructure in the shale and tight gas areas of Northeast B.C.;
5. Natural gas pipelines from the north;
6. The Board may also see 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.

Future developments could include:

1. Oil to the west coast of Canada to access new Asia markets;
2. Continued development of the Bakken oil play in Saskatchewan and North Dakota.

Thus, it is fairly certain to say that the NEB is and will continue to be in the thick of these moving pieces. As such, we try to exercise constant monitoring of energy supply and markets so that we can best position ourselves to respond in a timely and efficient manner to applications while having a transparent regulatory process.

NEB Areas of Responsibility

Aside from our regulatory role, 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 my views of future energy markets.

NEB Reports

The NEB releases several products under its mandate to help Canadians understand energy-sector trends, including projections into where the energy-sector may be going. 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

I will be referring to information from these reports, including information derived from the modeling within, several times in this talk.

Oil and Natural Gas Prices

This chart provides the price outlook for crude oil and natural gas from our 2009 Reference Case Scenario: Canadian Energy Demand and Supply to 2020 released in July 2009. The scales on the sides are adjusted for the energy equivalence of the two fuels (6:1).

Over the long term, in our medium case, you can see that we expected gas to recover to about US$6.50/MMbtu by mid 2011, and then maintain a slow but steady increase towards 2020. Since the release of the Energy Future update, we have released our Short-term Canadian Natural Gas Deliverability 2008-2010 report in September 2009 and our 2011 price is now expected to be under $6.

The disconnect in energy-equivalent prices is likely because of:

1. The ability of natural gas producers to quickly bring new gas to market in North America, which may be lowering NYMEX gas prices;
2. Long lead times in bringing new oil to market;
3. The oil price is largely international (strongly whereas the gas price is more continental.

Canadian Natural Gas Deliverability Short Term

Currently, Canadian rig activity is down some 60 per cent over what would normally be expected at this time of the year since 2005. We expect that the lack of drilling activity in western Canada in 2009, which is expected to continue into 2010, will cause production to drop in all cases until late 2010 at the earliest.

Production (gas prices at $5.75/GJ in 2011) is expected fall to 13.5 Bcf/d by 2011 in our medium case.

Of note is that only in the high case (gas prices at $7/GJ in 2011) do we expect production to even flatten in the near term.

Our low case ($4.00/GJ in 2011) has Canadian production falling to just over 12 Bcf/d by the end of 2011.

Canadian Natural Gas Production - Reference Case Scenario

More specifically, our long-term medium case from the Energy Future update can be broken out by production type: solution, conventional (non-associated) gas, tight gas, CBM, Shale Gas, and Frontier. Of note, Montney production is included within the Tight category. Shale is dominantly Horn River Basin with small amounts of Utica production. And frontier gas is currently Sable gas off east-coast Nova Scotia.

Importantly, there is a significant decline to Canadian production that started around 2006 and is projected to continue towards 2010 and 2011. While drilling activity in tight gas and shale gas steadily increases their share of Canadian production, it is not enough to offset conventional declines until 2011 and then production is expected to rise only slowly afterwards. In 2016, Frontier gas is supplemented by production from northern gas. Still, even with all these production additions, it is not expected that Canadian production will exceed past highs.

In the high-case estimate (not shown here), production growth in shale gas and tight gas creates incremental growth in Canadian production above previous highs. In the Low Case, tight gas and shale make key contributions to supply, but are not enough to stem the decline in conventional gas.

Canadian Natural Gas Pipeline Throughput

This chart shows throughput on various Canadian pipelines from January to June for the past three years, organized by markets served. The black line represents the capacity of the pipelines.

Many major pipelines have seen declines in throughput since 2007. This is due to declining production in the Western Canada Sedimentary Basin, which has fallen from around 17 Bcf/d in 2007 to about 14.5 Bcf/d so far in 2009 , 17 per cent. Furthermore, increasing consumption within Alberta, especially in the oil sands, has reduced flows on many Ex-Alberta pipelines.

In particular, flows on the western portion of TransCanada mainline have dropped by more than 1 Bcf/d from the first half of 2007 to the first half of 2009.

Alliance Pipeline is faring differently, running near full capacity, as it has since commencement of service. This is largely because gas volumes are contracted for the long term.

In the longer term, western Canadian unconventional supply originating from plays like the Montney and Horn River Basin in Northeast B.C. may reverse the trend of declining throughput. Currently, Northeast B.C. produces approximately 2.6 Bcf/d of natural gas is expected to grow to 3.2 Bcf/d (Short-term Deliverability medium case) by 2011. However, projected growth in B.C. production will likely not be enough to offset declines in Alberta production before 2011, suggesting pipeline throughput may fall further below capacity in coming years.

For producers from western Canada, there may possibly be higher pipeline tolls as operating costs are spread over less units of gas shipped. This increases shipping costs to reach markets in distant places like eastern Canada and the northeastern US. The combination of decreased supply and increased costs of shipping gas from western Canada may mean that gas production from Quebec becomes economically very attractive and fetches a significant price premium over western Canadian gas.

Heading Canadian Gas Off at the Pass

According to the EIA, 2008 was the most active year for U.S. natural gas pipeline construction in more than a decade. Companies completed 84 projects and put close to 6500 kilometres of pipe in the ground.

The Rockies Express Pipeline, one of the longest gas pipelines ever built in North America, has increased tight-gas supplies from Rocky Mountain basins in the western US to mid-west US markets by about 1.5 Bcf per day.

The East Texas to Mississippi Expansion, Gulf Crossing, Southeast Expansion, and Mid-Continent Express pipeline projects have also recently come online to add peak-day capacity of about 4.7 Bcf/d, mainly to deliver Texas and Louisiana shale gas to market.

Then there are a number of proposed pipelines in the eastern US with significant additional capacity. Proposed pipelines, of course, are in the planning stage and may never come to fruition because of economics or regulatory reasons, or their projected start dates may be significantly delayed, or their peak-day capacity may be revised downward.

All these newly in-service and proposed projects serve one purpose: to feed emerging US gas to US markets that have traditionally been served by Canadian pipeline systems. Furthermore, the availability of Rockies gas for import into Canada at the southwestern tip of Ontario has important implications for Canadian pipelines that serve the eastern Canadian market. More implications arise from growth of Marcellus Shale production in the northeast US, LNG imports, and potential Utica Shale production in Quebec and New York State.

Thus, Canadian pipeline companies may not be the only ones who will need to come up with inventive solutions for distributing Canadian gas, but perhaps producers as well. This potentially means finding new markets, as indicated by both Apache and EOG recently signing memorandums of understanding with the proposed Kitimat LNG export terminal.

Canadian Primary Energy Demand - All Fuels

This graph is derived from the appendices of our 2009 Energy Future update and illustrates Canadian primary energy demand by all fuels, broken down into Petajoules, and projected to 2020.

Overall Canadian energy demand is expected to grow significantly towards 2020.

All sectors show growth except for coal consumption, which is expected to decline by over 50 per cent by 2020.

And, importantly, growth in natural-gas demand to 2020 is projected to be moderate. Certainly, it does not appear to be an area of significant growth and it does not appear to be growing at the expense of any other sector except, perhaps, coal.

Oil Sands Gas Demand

One of the significant sectors for expected growth in Canadian gas demand comes from expansion of the oil sands.

This projection was released by the ERCB in June 2009.

It is no particular surprise that gas demand from the oil sands is still projected to grow into the future, reaching about 2 Bcf/d by 2015, just lower than the NEB's projection of 2.1 Bcf/d made in a 2006 update to our Energy Market Assessment "Canada's Oil Sands: Opportunities and Challenges to 2015".

Increasing demand in western Canada means the potential for less gas throughput on pipelines that serve eastern Canada.

Quebec Primary Energy Demand - All Fuels

This graph is also derived from the appendices of our 2009 Energy Future update.

Natural gas currently forms about 13 per cent of Quebec's total energy demand. Quebec current natural gas demand is about 0.6 to 0.7 Bcf/d, only about 5 per cent of all Canadian consumption.

Overall Quebec energy demand is expected to grow significantly towards 2020, like Canada's. However, the proportion of natural gas demand in Quebec is not expected increase its share, remaining around 13 per cent. In particular, when compared to the rest of the country, natural gas makes a much smaller component of Quebec's energy demand, largely due to the large supply of hydro-electric power available.

Quebec Pulp and Paper Sector - Energy Demand

The pulp and paper sector is currently about 25 per cent of all Quebec industrial-energy demand. Overall, pulp and paper sector energy consumption has decreased considerably in just the past few years and is expected to remain low. Much of this is the result of a downsizing in the Canadian pulp and paper industry as a whole.

Even more important has been the sector's large shift towards biofuels and away from other energy sources. Currently, 50 per cent of energy is from wood-waste products, whose usage has only declined mildly when compared to the decline in the Total Fuel demand. Fuels like oil and natural gas have shrunk far more considerably in a historical sense and are projected to continue declining well into the future.

Of course, growth in biofuels in an industry where overall energy use is expected to shrink must come at the expense of other fuels. Historically, much of this has come at the expense of natural gas, which has declined considerably since the 1990s and is expected to continue to decline.

Energy Demand Management and Environmental Programs and Policies

One of the biggest challenges in projecting energy demand is the implementation of policy by governmental bodies.

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. Furthermore, policies designed to improve energy efficiency, such as vehicle efficiency standards, are intended to reduce energy demand.

Even if policies are implemented, changes in fuel demand might occur slowly, in large part due to the large number of existing energy-using devices in the economy. Furthermore, significant infrastructure development with long lead times could be required to accommodate any shift in supply or demand. While legislation could encourage faster development and/or adoption of alternative and renewable fuels, it could also reduce demand for more conventional fuels.

The question that arises is how can natural gas still fit in any scheme that calls for increased usage of alternative and renewable fuels?

Quebec Electricity Generation Capacity - All Fuels

The major growth area of electricity-generation capacity projected for Quebec over the next twelve years is in wind power. According to the 2009 Energy Future update, we project Quebec wind-power generation to expand from its current 1 per cent of electricity generation to 16 per cent by 2020, whereas wind-power generation in Canada as a whole is "only" expected to grow from a 1% share to a 10% share. Meanwhile, we have projected negligible growth in natural gas generation capacity in Quebec from a very small proportion to begin with.

Many people in this room, however, recognize that wind power is an intermittent source of energy that relies on local weather conditions.

Canadian Electricity Generation Capacity - All Fuels

While local hydro backup can be desirable and there is no shortage of hydro power in Quebec, in other parts of Canada it can be a different story. There may be limited water resources available, such as in arid and windy areas of southern Alberta and Saskatchewan.

Therefore, some are suggesting the use of gas-fired electricity generation as backup. For example, peaking power plants - also known as peaker plants - are power-generation plants that are normally run only when there is high demand that exceeds the capacity of base-load power plants. Such peakers are often run in the afternoon, when people come home from work and turn on their computers, tvs, and ovens, and especially in the summer when air-conditioning demands are the highest.

Power generation from peaker plants can also be ramped up in a short amount of time. Of course, this could cause high swings of gas throughput on pipelines and rapid ramp up and ramp down of large volume and could have a significant impact on pipeline operations and could impact Quebec, which is near the end of the pipeline system.

Emissions - CCS

Much has been made of carbon capture and storage as a method to decrease greenhouse-gas emissions. However, currently, the main hurdles to its development are its cost framework and technological capabilities.

Uncertainty in CCS may, therefore, cause risk-wary members of the power sector to instead support gas-fired electrical generation because the technological requirements are very well known. And natural gas emits one half or less the greenhouse gases than using coal as a source fuel, still allowing gas-fired electrical plants to help reduce overall greenhouse-gas emissions from current levels.

Even without current implementation of CCS, coal's share of power generation in the US has fallen from 49 per cent to 45 per cent from 2007. Furthermore, coal-fired generation fell almost 13 per cent from the first half of 2008 to the first half of 2009, while gas-fired generation rose almost 2 per cent.

Siting

Of course, within any growing energy market, there can come the need for additional infrastructure to deliver energy to it. This is not restricted to just natural gas, but electrical-power lines as well. Such development can require significant stretches of infrastructure over public and private land. This, of course, requires significant consultation with stakeholders.

Most of the NEB's work is with pipelines, but public interest issues are similar for electricity transmission. Long distance electricity transmission lines (such as those in Manitoba associated with the Lower Churchill project), whether they are regulated by the NEB or not, sometimes meet public opposition. Not-in-my-backyard concerns on long-distance electricity-transmission lines may favor gas turbines that can be sited close to markets, especially if the pipeline infrastructure is already in place to deliver that gas.

Conclusions...

Just five years ago, it was looking like North American natural gas markets could be entering a period of peak domestic gas and the onset of LNG as the major area of supply growth. Now, the natural-gas upstream and midstream industries are facing a challenging pricing environment as their own ability to get gas to market appears to be greatly surpassing demand growth. There is also competition between domestic North American producers as US producers are shipping increasing volumes of gas to markets traditionally served by Canadian long-haul pipelines.

Market conditions for supply, demand and pipeline utilization will likely continue to evolve and innovative solutions will be required to adapt to changing circumstances. I cannot offer you solutions, but I can say this: an industry that manages to get natural gas out of shale likely has the brains to meet the challenges of an uncertain future.

Thank you!

 

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Date Modified:

2011-10-28