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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

CSUG Conference

18 November 2009

I wish to thank the Canadian Society for Unconventional Gas (CSUG) for inviting me to participate in this important event.

I am a Board Member of the National Energy Board of Canada, a public institution 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 per cent 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 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:

• 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 mayl 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?

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

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:

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

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.

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 while having a transparent regulatory process.

NEB Areas of Responsibility

Normally a regulatory body would be quite content to stand well back from the front lines of a high risk operation like making projections of energy supply, demand and transmission.

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 these mandates 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

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.

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 Energy Future Reference Case update.

The price of West Texas Intermediate (WTI) crude oil at Cushing Oklahoma 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).

As you are aware, there has been a disconnect between energy equivalent oil and natural gas prices since 2005. The price of oil grew substantially from 2005 to mid-2008 while the price of natural gas remained relatively flat until the price spike observed in the first half of 2008. Since then, both prices have fallen, but the disconnect remains and is expected to remain into the future. Note that our projected prices are not set by models, but by industry consultation on likely low, medium, and high values. Over the long term, in our medium case, you can see that we expected gas to recover to about $6.50 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 Natural Gas Deliverability report and our 2011 price is now expected to be under $6.

Why is there is disconnect between oil and gas price? Among many things, there is much optimism in the ability of natural gas producers to bring new gas to market in North America, which may be lowering NYMEX gas prices, whereas long lead times in bringing new oil to market, along with high rates of expected demand growth in developing nations, may be encouraging higher oil prices. Furthermore, oil-production management by OPEC can constrain oil production while natural gas has no such management other than simple supply-demand fundamentals which are mostly continental rather than international.

Canadian Natural Gas Deliverability Short Term

Before we step into discussing natural gas markets, we should briefly discuss projections of Canadian natural gas supply to understand just what might be available in Canada to get to those markets.

Currently, Canadian rig activity is down some 60 per cent over what would normally be expected at this time of the year since 2005. What drilling remains is focusing on deep plays, in particular with many wells drilled with long horizontal reaches and extensive well stimulation. While productivity in these deeper wells tends to be higher, they require significantly more time to drill and therefore fewer wells are drilled as a result.

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. Much of this production decline is momentum, with current low activity being felt down the line. While we have little doubt that exploration companies have many locations in their books available to be drilled, it takes time for rig fleets to mobilize and capital to be raised for any rebound to occur in the event of price recovery. Of note is that only in the high case (gas prices at $7 in 2011) do we expect production to even flatten in the near term. And our low case ($4.00 in 2011) has Canadian production falling to just over 12 Bcf/d by the end of 2011. Even the medium case ($5.50 in 2011) sees production falling to just over 13 Bcf/d by the end of 2011, much of it likely to do with an extended period of low prices before they recover and the inability of operators and drillers to move as quickly in response.

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.

Now the question is, of course, how do these projections impact infrastructure?

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, and which is projected to decline further. Furthermore, increasing consumption within Alberta, especially in the oil sands, has reduced flows on many Ex-Alberta pipelines.

Flows on the western portion of TransCanada mainline have dropped by more than 1 Bcf/d from the first half of 2007 compared to the first half of 2009. Capacity, as shown on the graph by the black line, is as of January 2009, after the decommissioning of line 100-1 as part of the Keystone Pipeline Project, so it could flow crude oil from growing oil sands production instead of gas (the NEB regulatory decision effective July 2008). This reduced gas-throughput on the TransCanada mainline by approximately 0.5 BCF/D.

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 and any remaining space in the pipeline is filled because of the pipeline's Authorized Overrun Service (AOS), which enables shippers to flow volumes in excess of their firm contract for the cost of fuel only.

In the longer term, as discussed on the previous slide, western Canadian unconventional supply originating from plays like the Montney and Horn River in Northeast B.C. may boost production and reverse the trend of declining throughput. Currently, Northeast B.C. produces approximately 2.6 Bcf/d of natural gas and the recently released 2009 Reference Case update suggests that this may grow to 3.3 Bcf/d (medium case) by 2011. However, as also discussed in the previous slides, the 2009 Reference Case update and our Short-term Deliverability projection both conclude that 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.

In recent developments in eastern Canadian pipelines, in late June 2009, the Canaport LNG terminal in New Brunswick received its first commissioning cargo and deliveries from the terminal commenced on July 9th. Since then, average sendout from the terminal is about 160 MMcf/d which flows into the Maritimes and Northeast Pipeline. In addition to existing Sable Island gas production, Deep Panuke is expected to come online sometime in 2010 and fill much of the remaining capacity.

It must be asked: what challenges do producers face in this scheme of declining throughput in most major Canadian pipeline systems?

There may possibly be higher pipeline tolls as operating costs are spread over less units of gas shipped. This would be somewhat offset by decreased fuel costs for pipeline compression, but it is difficult to get an estimate of the end result.

Pipeline companies have and will need to look for inventive solutions to declining throughput.

Furthermore, with declining production comes the possibility of pipeline abandonment elsewhere in the Western Canada Sedimentary Basin., which will come with its own cost.

Heading Canadian Gas Off at the Pass

Heading Canadian gas off at the pass. Or how US pipeline projects plan to turn on the taps and give Canadian producers a real challenge.

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. Much of the construction was in northern Texas and Rocky Mountain basins, driven by unconventional supply growth. The Rockies Express Pipeline, one of the longest gas pipelines ever built in North America, has increased gas supplies from Rocky Mountain basins in the western US to mid-west US markets by about 1.5 Bcf per day.

Also worth noting is that 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. These systems feed northeast bound pipelines that have experienced throughput declines as Gulf of Mexico gas production has waned.

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. Regardless, planned pipeline projects demonstrate the intent of pipeline companies to deliver growing shale-gas and tight-gas potential to expected growth markets.

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, like Alliance and TCPL's Transmission Mainline. Furthermore, the availability of Rockies gas for import into Canada near the Dawn Hub at the southwestern tip of Ontario has important implications for Canadian pipelines that serve the eastern Canadian market. From 1.9 to 3.4 Bcf/d flows into the southwestern tip of Ontario, depending on the season. While most of that gas originates from western Canadian production, a significant and growing portion of that gas originates from US production. While some of that gas is locally re-exported, growing US gas supplies may be able to displace eastbound western Canadian gas in the future. 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. Essentially, major sectors of the Canadian economy (residential, transportation, commercial, and industrial) are further broken down into their individual components (such as single-family homes in residential or refinery demand in industrial), which are modeled on a province by province basis. The sum of the provincial models results in the aggregate above.

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.

Of course, the devil is in the details.

Oil Sands Gas Demand

This data was released by the ERCB in June 2009, after much reorganization occurred in the oil sands sector during the previous year. Oil sands gas demand is based on mining, in-situ steam generation, as well as bitumen upgrading.

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".

Concurrently, there is an expected significant increase for natural-gas liquid demand, which is required for diluent to transport bitumen in pipelines. As is generally known, the northern fringe of the Montney, Doig, and Doig Phosphate tight-gas play areas are more liquid rich. This is a potential way to add value to production.

Pulp and Paper Sector - Energy Demand

The chart on the screen has been derived from our demand modeling. The pulp and paper sector is currently about 20 per cent of all Canadian industrial-energy demand. Overall, its energy consumption has decreased considerably in just the past few years and is expected to remain low into the future. Much of this is the result of a downsizing in the Canadian pulp and paper industry.

Even more important has been its large shift towards biofuels and away from other energy sources. Currently, 60 per cent of energy is from wood-waste products and the industry plans to grow this to as high as possible. Some in the forestry industry have even proposed the use of wood derived from trees killed by the Asian pine beetle as another source of energy, to be gasified and then burned for electricity. Otherwise there is very limited commercial use for wood from these dead trees and it becomes a practical solution that helps the local forestry sector and local economies.

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.

This is not the only component of the industrial sector expected to decrease its natural gas consumption. The auto sector in Ontario has been greatly downsized in the recent economic turmoil. We're also seeing capacity shrinking in the steel industry as lower cost offshore sources compete with our domestic producers. All this will also impact future demand of natural gas.

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 and were not included in the previous projections.

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?

Backup for Wind Power?

Many advocates who hope for a growth in renewable energy are calling for significant expansion of wind-generated electricity. According to the 2009 Energy Future update, we project that wind-generated electricity will expand from its current 1 per cent of generation capacity to 10 per cent by 2020. Many people in this room, however, recognize that wind power is an intermittent source of energy that relies on local weather conditions that can change with little advance notice.

While local hydro backup can be desirable, 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.

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.

In any carbon-cap and trade system, the carbon price must be enough to earn the plant enough revenue so its investors can earn back their investments and even make a reasonable profit. Further, the longer it takes to define regulations, the shorter the lead times may be before reduction targets must be met. This impacts CCS because CCS requires significant infrastructure to be built beyond the power plant, such as the facilities to capture the CO₂, construction of corrosion-resistant pipelines, and injection wells. There is also much technological uncertainty associated with CCS. While Weyburn has been demonstrated to be successful, it is still very uncertain whether CCS can be applied on a massive scale.

Significant 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, such as the proposers of the infrastructure, the general public, NGOs, First Nations, local landholders, community groups, and organizations. After all, once the pipeline is in the ground or the transmission lines are strung across hundreds of kilometres, they are very difficult to move or change!

Most of the NEB's work is with pipelines, but public interest issues are similar for electricity transmission. Long distance 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. Being closer to market would also reduce the costs and energy loss of having to deliver electricity over long distances.

Conclusions...

In these uncertain times, how can one come to confident 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. How things have changed since then. 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. Furthermore, competition against LNG is also growing. 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.

Resulting low gas prices may go so far as to encourage fuel switching from other fossil-fuel sources, like coal. Other areas of demand growth are largely conceptual at the moment, but there are some advantages that natural gas has over other fuel types, especially when demand-management by policy makers is taken into consideration.

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 offer the market what it needs to meet energy demand.

Thank you!

 

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Date Modified:

2011-10-28