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Home > Speeches and Presentations > Speeches and Presentations 2009 > An NEB Perspective on Trends in Canadian Oil Supply

An NEB Perspective on Trends in Canadian Oil Supply

Presented by
Kenneth Bateman
Board Member
National Energy Board

The Canadian Institute's 2^nd North American Pipelines Conference
Calgary, Alberta

19 February 2009

An NEB Perspective on Trends in Canadian Oil Supply

Good morning everyone. It is indeed an honour to be presenting at this 2^nd North American Pipelines conference.

Change is inevitable - except from a vending machine

While change may be inevitable, few could have foreseen the extent to which global financial and commodity markets have been roiled over the past eight months or so. Oil prices which peaked at $147 in July receded to $34 by December, while NYMEX natural gas prices which hit $US13 in June fell to $5 in January of this year. Financial turmoil ensued as the global financial system lost confidence and floundered, resulting in a freeze-up of credit. Financial institutions around the world discovered what Warren Buffett meant when he described the various exotic derivatives and mortgage-backed securities as "seeds of mass financial destruction". Although financial markets have recovered to some extent, in this environment, some companies struggle to survive, and almost all have sharply reduced their spending plans. For instance, in the oil sands, some $90 billion of projects have been postponed or cancelled, oil and gas drilling levels have been cut by over 20% compared to last year. Many jobs have been cut, especially in the service sector. This economic collapse has been termed by some as a "black swan" or once in a lifetime event. Let's hope so.

In deference to Alan Greenspan's "irrational exuberance" in 2001, what we have now could be termed "irrational pessimism" or maybe we're "mired in melancholy". But it's not all doom and gloom.

On the positive side, some companies, among them ExxonMobil, Total, Devon, Meg Energy, are moving ahead with their oil sands projects, amid indications that costs for material such as steel and cement are coming down. Service contracts are being re-negotiated. The Stelmach government recently announced an incentive package for Small to mid-cap operators in Alberta.

Many analysts are predicting a recovery of oil prices to the $65 to $75 level over the second half of 2009, as oil supply and demand rebalance and markets stabilize. For investment levels in oil sands to rebound we'll also need to see improved access to credit markets. Make no mistake - the oil sands industry has been dealt a serious blow, whose impact may be felt for years to come.

The recent protectionist sentiment displayed south of the border, and opposition to imports of "dirty oil" have been a concern for many in the industry, and point out the need for agreements with Canada's major trading partner on the environmental, trade and security of supply issues.

As for the impact on the NEB, we anticipate some reduction or re-scheduling of applications coming before us, but to date the effect has been minimal.

Although I do plan to present NEB's outlook on Canadian oil supply, I would first like to briefly outline the NEB's role in pipeline regulation, as well as our strategic priorities and some of the initiatives we are taking to improve the level of service we provide to Canadians.

Mandate and Purpose

Three main acts from which the NEB's mandate is derived: National Energy Board Act, Canadian Oil and Gas Operations Act, Canada Petroleum Resources Act. The latter two acts govern our activities in "frontier" areas.

Areas of Responsibility

Under its regulatory mandate, the board is primarily responsible for

Physical and financial regulation of pipelines that cross provincial & international boundaries
Physical regulation of certain international power lines
International trade in oil, natural gas and electricity
Exploration and production of petroleum in the Non-Accord areas

In its advisory capacity, the board

Monitors energy markets
Provides advice to the federal government
Issues reports on energy issues

Gas pipelines - Oil pipelines

The NEB regulates more than 45,000 kilometres of pipelines across Canada. Natural gas pipelines account for about 2/3 of this total, and oil pipelines about 1/3. In 2008, it is estimated that these pipelines shipped over $127 billion worth of natural gas, crude oil, petroleum products and natural gas liquids, at an estimated transportation cost of $4.4 billion. Clearly, pipeline systems provide huge economic benefits to Canadians.

As I'm sure most of you are aware, TransCanada has applied to the Board to have regulatory responsibility for its Alberta System shifted from the Province of Alberta to the NEB. I can say little about this since it's still before the Board, except that if we do inherit the Alberta System, we will have an additional 23,000 kilometres of pipe under our purview.

NEB Priorities

In the fall of each year Board Members and senior staff of the NEB meet to determine if goals and responsibilities are being met, and to set the Strategic Plan going forward. Feedback from stakeholders is an integral part of this process, and industry players are invited to put forward their views. Our Strategic Plan has four major themes, as outlined above. I will expand on these themes in the next few slides.

Safety

The safe and secure delivery of energy is of utmost importance to the NEB. It was disappointing to see that, in 2007 and 2008, there was an increase in the number of serious-injury accidents at NEB regulated facilities, with two incidents recorded in 2007 and five in 2008, which included two fatalities, the first since 1997. The increase may have been a result of the rapid pace of construction that occurred during this period. NEB responded with an increased number of inspections, audits and compliance screenings.

The NEB continues to foster partnerships with industry, industry associations, and other government and regulatory agencies to enhance the sharing of knowledge and promotion of best practices, in order to further our ability to ensure all NEB regulated facilities and activities remain safe and secure.

Through our involvement with the Canadian Standards Association (CSA) we contributed to the development of a new security standard for oil and gas and pipeline companies. We also expanded our risk-based lifecycle management system to include a security inspection during the construction phase of a pipeline.

Energy and the Environment

The NEB takes a life cycle approach to regulation. We are involved from the pre-application and application stages, through construction and long-term operations, and through the abandonment of the project.

If a project is approved, the NEB ensures the company continues to protect the environment, public health and safety by auditing and inspecting the company's construction activities, maintenance program and monitoring procedures during the operation of the pipeline.

It is becoming quite common these days to hear people say that energy and the environment are inseparable. That's why the NEB is continually updating its tool kit to be current and well equipped to deal with the growing expectations of Canadians.

We have been dealing with environmental matters for a long time. Our original mandate, codified in the original, 1959 version of the National Energy Board Act, already envisaged the integration, into one decision, of all public interest matters that appear to the Board to be relevant. In infrastructure cases that are brought before us, environmental matters have been consistently of relevance for a long time. What is changing, and will continue to change, is not whether we need to care for the environment, but the manner in which we do so.

For about 10 years now, we have moved proactively towards the concept of goal-oriented regulation. This means that we are in the business of stipulating what the goals, the outcomes, the results should be, holding companies who undertake energy projects responsible to meet these results, while leaving the companies the latitude they need to choose the how, so that they may respond more effectively to actual conditions they encounter in the field as they build projects.

GOSAT (IBUKI)

Consistent with the theme of environmental protection, I'd thought I'd present this item which recently came to my attention.

On January 23 this year, the Japanese Space Agency launched GOSAT (Global Greenhouse Observation by Satellite), also known by its Japanese name, "Ibuki".

The GOSAT mission is designed to identify and monitor sources of CO₂, to support compliance with international treaties and agreements such as Kyoto.

GOSAT will take measurements of two key greenhouse gases - carbon dioxide (CO₂) and methane (CH₄) - over nearly the entire surface of the planet. So far, the number of ground-based carbon dioxide observation points has been limited, and they have been distributed unequally throughout the world. "IBUKI" will enable the precise monitoring of the density of carbon dioxide by combining global observation data sent from space with data obtained on land, and with simulation models.

It will also serve to indentify carbon "sinks", or areas where carbon is absorbed. This is important, because atmospheric scientists believe that, based on their knowledge of forest and ocean net carbon sinks, that they are failing to account for a carbon sink of about 1 to 3 trillion kilograms.

In late February, NASA plans to launch a satellite dubbed "OCO" or (Orbiting Carbon Observatory), whose prime objective is to find the CO₂ sinks.

Hopefully, these scientific initiatives will go some way towards further defining the mechanisms of global warming, and provide some insight on how these effects can best be mitigated.

Land Matters

A great deal of the feedback we've received from stakeholders has centred on:

The growing concerns about the impacts of energy infrastructure projects on the land, and on people who live on and off the land;
The clear expectations on the part of citizens that environmental impacts will be avoided or mitigated, through design choices, or mitigating measures; and
The desire of citizens to be meaningfully engaged in decision-making processes dealing with energy projects.

These three drivers motivated us, a year ago, to initiate the Land Matters Consultation Initiative (LMCI). The key areas being considered in the LMCI are:

company interactions with landowners;
improving the accessibility of NEB Processes;
pipeline abandonment - financial issues; and
pipeline abandonment - physical issues.

With respect to the 3^rd area, pipeline abandonment - financial issues, the Board is holding a hearing, RH-2-2008, that began on 20 January 2009.

With respect to the other three areas, in the last year, we have held information and consultation about land matters in 25 communities across Canada. We have produced, in consultation with stakeholders, 4 discussion papers about land matters.

We expect that, as a result of the LMCI, we will be in a much better position to deal with land matters throughout the life cycle of regulation, namely, before applications are filed, as part of the regulatory process, during construction, during operation, and when dealing with applications for abandonment.

Engaging ENGOs

In parallel to the LMCI, we have also entered into an agreement with the Pembina Institute to reach out to Canada's environmental non-governmental organizations. We have spoken with 10 of Canada's most active and influential environmental advocates and in the coming months, plan to meet with the leaders of these organizations to discuss better ways of protecting the environment during pipeline construction and operation. Our goal is to help persons with environmental interests to see in the NEB regulatory process a credible and trusted place for environmental discussions and debates to take place in respect of NEB-regulated facilities.

Regulatory Effectiveness & Efficiency

The NEB continually strives to improve its regulatory processes to ensure they are effective and efficient.

Of particular note is the work we did with the Federal Major Projects Management Office to improve the efficiency and effectiveness of the federal regulatory review process. NEB staff made significant contributions to this initiative, and in particular, the work that was done to formalise an Enhanced Aboriginal Engagement process for NEB regulated projects - the MPMO is now in operation and has most of its tools ready for action.

We also participated in the following initiatives:

the Northern Regulatory Improvement Initiative launched by former Minister Strahl of Indian and Northern Affairs Canada on November 7^th, 2007;
The regulatory improvement work carried out under the auspices of the Conference of Energy and Mines Ministers, with the goal of sharing best practices among federal, provincial, and territorial regulators throughout Canada. The NEB works through our association of regulators, CAMPUT, in this area.

Board staff continue to monitor energy and transportation markets in order to provide useful, objective and timely energy market information to Canadians. In this regard, in 2008 the Board published four major energy reports, and many other briefing notes and articles. The NEB website has proven to be a valuable resource for Canadians and others seeking information about energy related matters in Canada.

Service Standards (sample)

I mentioned earlier the importance to Canadians that the regulatory process be clear, well understood and timely.

Informing Canadians of the time it takes to process applications is part of our commitment to transparency and regulatory efficiency. Every year, we publish our service standards, and we inform Canadians of our performance under these service standards. These are our latest published performance results relative to our service standards for a range of tasks.

Current Economic Outlook

The global economy is in the most synchronized recession in the post-war period. The slowdown is particularly evident in the United States and other advanced economies, but it is also increasinly apparent in emerging market economies. Please see the chart on the left hand side of the slide. The US, Japan, and Euro area are all expected to have negative economic growth in 2009 and China's economic growth is expected to slow significantly. Resulting world economic growth is expected to be around 1 percent, well below the rate usually associated with a global recession.

It is generally agreed that the Canadian economy entered into a recession in the fourth quarter of 2008. Canada's economic slowdown is being driven by the following key factors:

Global financial crisis resulting in tighter credit conditions and equity market losses;
Economic slowdown in the US and other key economies, which has reduced demand for Canadian exports;
Decrease in prices for commodities produced in Canada, which is lowering Canadian profit and income growth.

There is general concensus that the recession in Canada will last three quarters (2008Q4 to 2009Q2). This means that the first half of 2009 will be challenging for Canadians. However, the Canadian economy is expected to begin to recover in the second half of 2009 with economic growth rebounding in 2010.

The chart on the right hand side of the slide shows various forecasts for Canadian economic growth over the next eight quarters. Although the future is difficult to predict, this provides a range of potential outcomes. On an annual basis, concensus economic growth for 2009 averages - 0.8 percent and the average for 2010 is 2.4 percent.

Canadian Oil 2008

I thought I'd set the stage for the discussion of oil supply by providing a few industry metrics for 2008.

Thanks to the huge oil sands endowment, Canada's remaining oil reserves stand at 179 billion barrels, ranking us second in the world, after Saudi Arabia, according to the Oil and Gas Journal, among others. Canada's reserves are comprised of about 174 Billion barrels of oil sands bitumen and about four billion barrels of conventional light and heavy reserves.

Production: In 2008, Canadian production of crude oil and equivalent averaged 2.7 million barrels per day, roughly the same as in 2007. The growth in oil sands production was moderated by operational difficulties at the major upgrading plants, but still offset declining conventional production in the WCSB and the East coast offshore.

Canada is the world's seventh largest producer of crude oil, and is in fact the largest supplier of oil to the US. In 2008, crude oil exports averaged 1.85 million barrels per day which represents a year-on-year increase of three percent. The estimated value of crude oil exports for 2008 is $80.5 billion compared with $42.5 billion in 2007.

Canada's Energy Future: Reference Case and Scenarios to 2030

The long term views on crude oil supply I'll be providing today are based on the NEB's 2007 Report on Canada's Energy Future. The report provided a comprehensive outlook of energy supply and demand for the years 2005 to 2030. The study consists of a reference case analysis from 2005-2015 and an analysis of three scenarios, which extend out to the year 2030.

This report developed crude oil supply projections out to 2030, in three different scenarios, with three different price tracks.

Although the analyses for the report was completed about 2 years ago, in general, we are still confident that the long-term projections of oil supply are reasonable.

In the past, we have done the Energy Futures reports on a 4-year cycle. We have been asked by some of our stakeholders to provide updates on a two-year basis. Given this request, and the tremendous volatility of oil and gas markets over the last year we are considering providing an update of our Reference Case. This would feature a revised look ahead to 2020, including a revised outlook on oil supply.

Crude Oil & Natural Gas Prices

For the three scenarios, oil prices were assumed to be varied from $35, $50 and $85 ($US WTI at Cushing), with corresponding gas prices of $5.50, $7 and $12 ($2007 US/MMcf at Henry Hub).

When oil prices escalated to $147 last summer, we thought our price projections were way off track, today they're looking much better.

Total Crude Oil Supply

In our Energy Futures Report, by 2030, total crude oil production in Canada ranges between 3.1 and 5.6 MMb/d across the 3 scenarios, with oil sands making up about 85 to 90 percent of the total, depending on the scenario.
In the Reference Case, the middle curve, production reaches 4.1 MMb/d by 2015.

As I stated a moment ago, we are reasonably comfortable with projections of the oil supply reached by 2030.

2009 Canadian Crude Oil Production Forecast

I would now like to turn the focus of my talk to near-term supply trends. On our Website, along with a host of other energy data and information, we provide historical oil production data along with a forecast of production for 2009, by province and crude oil type. The 3 lower wedges represent Western Canada conventional light, conventional heavy and condensate production, respectively. Reflecting a maturely explored basin, the conventional production in Western Canada has been in a long-term decline, at about five percent over the last ten years, but has flattened over the last year or so. The condensate production is derived largely from natural gas production, and has declined a rate of one percent over ten years. Offshore Newfoundland and Labrador production peaked in 2007 and has been declining at about 11 percent since. Over the last 5 years oil sands derived production has grown at a rate of eight percent per year, and we are showing considerable growth in oil sands in 2009 as several new upgrading and in situ projects ramp up through the year.

Total production in 2009 is forecast to be 2.84 MMb/d, roughly 2.5 percent above 2008 levels.

Trends in WCSB Conventional Oil Production

As indicated on the charts on the left, conventional light and conventional heavy in Alberta exhibit a well-defined historical decline, about 5.4 percent per year for light and 4.6 percent for heavy, and these declines extend in to 2009.

Saskatchewan production has been rising over the last 3 years, due to the success of the Bakken play and the Weyburn CO₂ Enhanced Oil Recovery project. I'll talk a bit more about these later.

Saskatchewan heavy production has remained relatively flat over the last 2 to 3 years.

2009 forecast production for Alberta is 470 mb/d and 450 mb/d for Saskatchewan.

Eastern Canada

This chart is from our Reference Case/Continuing Trends Scenario from the 2007 Energy Futures report. The actual production shown here for 2007 and 2008 is a bit less than predicted. In our 2009 forecast we have eastern Canada at 239 mb/d, down due to some equipment maintenance at Terra Nova. Production levels are expected to recover in 2010.

While there is still active development and exploration on the east Coast, our view on timing for major projects has changed.

Where we had previously predicted the Hebron Field to come on stream in 2013 and an additional large discovery coming on stream in 2016, these dates have now been pushed forward to 2018 and post 2020 respectively.

Oil Sands Supply

In our 2009 forecast we see sharply higher Synthetic crude oil production, as the result of the ramp up of two new projects, the CNRL Horizon integrated mining and upgrading project, and the OPTI/Nexen Long Lake project, which is an integrated SAGD and upgrading project. These two projects are expected to reach their full operating capacities (110,000 b/d and 60,000 b/d respectively, within 12 to 18 months. As well, Suncor will be able to take advantage of a mid-2008 expansion, and the upgraders are assumed to have less down time for maintenance than in 2008.

Based on continuing growth for in situ bitumen production, and adjusted for in situ bitumen volumes that are upgraded, the non-upgraded bitumen category is estimated to increase by about 5% for 2009.

Combined, oil sands supply grows to 1.44 MMb/d in 2009.

Oil Sands Production Forecasts

Rapidly rising costs were already delaying projects before a collapse in world oil prices and the global financial crisis, with the accompanying freeze-up of credit markets, dealt a severe blow to the economics of building oil sands projects.

Over the past 6 months or so, it is estimated that about $90 billion worth of projects have been delayed or deferred in some fashion.

To illustrate the loss of production tied to these delays, we're comparing a December 2008 CAPP forecast (Moderate case) with a previous CAPP forecast from June 2008 (Moderate case) and the 2007 NEB Continuing Trends forecast.

This provides us with only a very rough estimate, but the change in expectations relative to the 2007 NEB forecast is about 400,000 b/d. For the more recent CAPP forecasts, the gap between them widens as project start-up dates get pushed further into the future in the lower curve. This gap is 160 000 b/d in 2012 and 420 000 b/d in 2015.

Of note is that these curves assume substantive growth in oil sands production, reaching 3.8 MMb/d by 2020.

Local Upgrading ?

This chart, from our 2007 Energy Futures Report, shows our projected levels of upgraded bitumen and non-upgraded bitumen, with the curve indicating the fraction of the total that is upgraded. In percentage terms, the curve peaks at 72% and then moderates a bit to 64% by 2030.

However, our assumptions about the level of upgrading in Alberta will have to be revisited, as serious questions on this matter have come to the fore.

Currently, nearly 60 percent of the province's bitumen production is upgraded in Alberta. As a result of the deteriorating economic conditions, however, seven of eight proposals to upgrade future bitumen production in the province have been put on hold. As new bitumen projects come on stream, without upgrading, the pendulum swings to the non-upgraded side.

Where future bitumen production will be upgraded- in Canada or at refineries in the U.S, is the central issue now facing the North American refining industry. The President of the Canadian Association of Petroleum Producers (or CAPP) has indicated that, given Alberta's higher cost structure, it may be cheaper to re-configure existing facilities in the U.S. On the other hand, the province of Alberta is considering taking its share of bitumen royalties in kind and has indicated its desire to upgrade this supply in the province, to keep the "added-value" in Alberta.

Of course, more bitumen production also means more condensate for blending is needed, as well as more pipeline capacity to move the blended bitumen to market.

I think you will agree that this is a key issue facing the North American refining sector and one that needs to be addressed in a timely way.

Bakken Oil Play

The United States Geological Survey (USGS) has estimated that there are roughly 3 to 4.3 billion barrels of recoverable oil in place on the American side of the reservoir. Although no official estimate has been released on reserves buried under Canadian ground, with one quarter of the areal extent of the reservoir in Canada, a rough estimate would be about 1 billion barrels. This could prove to be an important source of conventional oil for Canada.

The successful exploitation of this previously bypassed oil was made possible by recent advances in horizontal drilling and fracturing technology. Horizontal drilling, with multi-leg wells and multi-fracturing techniques provides much greater access to the reservoir, and results in much better recovery rates.

Bakken Oil Production

This slide shows some of the activity and performance metrics for the Bakken play in Saskatchewan.

The number of horizontal wells drilled has been increasing rapidly since 2004, reaching a cumulative total of nearly 700 wells in 2008. Over the same period, production has increased from minor amounts to a level of 40,000 b/d.

The horizontal wells are much more prolific producers than their vertical counterparts, with the result that the average per well daily rate has increased about 3 fold to 60 b/d.

Weyburn CO₂ EOR Project

The Encana CO₂ Enhanced Oil Recovery project in southeastern Saskatchewan at Weyburn has achieved great success, doubling the oil production rate in an aging field to 30 thousand barrels per day and adding 155 million barrels of reserves.

The CO₂ injection methodology has the advantage of increasing recovery while also reducing greenhouse gases released into the atmosphere.

According to Encana, more than 13 million tonnes of CO₂ have been safely sequestered at Weyburn since start-up of the CO₂ flood, and, over the life of the field, it is projected that about 30 million tonnes of CO₂ will be stored in total. Some analysts are predicting the portion upgraded in Alberta will fall to 50% or below.

In addition to the Weyburn project, a CO₂ project is also in place at Midale, Saskatchewan and there are 5 or 6 smaller pilot projects in Alberta.

The Weyburn field and the neighbouring Midale field are the subject of a large-scale international research effort, led by the Petroleum Technology Research Centre in Regina, into gaining a comprehensive understanding of carbon sequestration and storage.

CO₂ EOR is only one part of the larger Carbon capture and storage effort envisaged to deal with greenhouse gases and there are still significant technological and financial hurdles to overcome before widespread Carbon capture and storage projects are in operation. No doubt the 2 billion dollars the Alberta government has earmarked for this problem, and the assistance of other governments, will be of some benefit in moving this file forward.

In Western Canada, the average recovery factor for heavy oil pools is about 12%, for light pools about 30%, and we think that this oil left behind will become an increasingly important source of oil supply. In our Triple E, or most environmentally friendly scenario, we attributed 1 billion bbls of additional recovery to CO₂ EOR.

Supply Forecast and Proposed Pipeline Projects

This chart is based on our June 2008 report on Canadian Pipeline Transportation Systems, and is updated to include recent announcements regarding pipeline expansion projects.

The chart indicates, in broad terms, how pipeline capacity will need to expand to meet the increasing levels of crude oil supply projected for Western Canada. The supply curve is the Continuing Trends curve from our 2007 Energy Futures report, adjusted for Western Canada refining demand. The solid blue bars on the bottom represent existing capacity out of Western Canada, and the various pipeline proposals are added to the chart in their scheduled start-up year. No priority is assigned to any particular proposal.

The supply curves reach about 3.7 MMb/d by 2020, and clearly there are more than enough capacity expansion proposals to meet this requirement.

Northern American Crude Oil Pipeline Proposals

The pipeline map shown here has been updated to include recent announcements regarding proposed new pipelines and expansions to existing systems.

You may recall that, in 2007, many oil pipeline systems were at or near capacity and at times were under apportionment. As a result of these circumstances, a number of proposals emerged to provide additional pipeline capacity to transport crude oil and to provide additional supplies of diluent required to support growing oil sands operations. Some of this additional pipeline capacity has been approved and is now under construction, and will increase market penetration of Canadian crude oil. Other projects are still in the planning stage.

Pipeline capacity continued to be tight in 2008, with all major export pipelines experiencing some apportionment, at times, during the course of the year. Early in the year, Kinder Morgan announced that it re-scoped its Anchor Loop project to add incremental capacity of 25 Mb/d on 1 May 2008 and an additional 15 Mb/d on 1 November. This provided some relief to the tight capacity situation, particularly in the second and third quarters of 2008.

There are two major crude oil pipeline expansions occurring in the next two years that will add significant pipeline capacity out of western Canada. They include the Trans Canada Keystone Pipeline which will be in-service December 2009 and will add 435 Mb/d of take away capacity to Wood River, Illinois, and Enbridge's Alberta Clipper Pipeline which will add 450 Mb/d of take away capacity in July 2010. Trans Canada also received NEB approval in July 2008 to expand its Keystone pipeline by 155 Mb/d and extend it to Cushing, OK. The expected in-service date is late 2010.

Trans Canada has also announced the Keystone Gulf Coast Expansion Project (Keystone XL). This project would include new pipeline construction in Canada and integrate a portion of the Keystone Pipeline already being constructed. Total system capacity would increase to about 1.1 million b/d and the estimated in-service date is 2012. As shown on the map, there are other proposals to tap the U.S. Gulf Coast market. Enbridge's Texas Access Pipeline, originally slated to be in-service in the 2011-2012 timeframe now has an estimated in-service date of 2014. The capacity of this pipeline would be 400 Mb/d. Kinder Morgan, in partnership with TEPPCO, have proposed the Chinook pipeline which would have a capacity of 300 Mb/d to transport crude oil to the U.S. Gulf Coast. The estimated in-service date is 2011. Altex is also proposing a bullet pipeline to the U.S. Gulf Coast with a capacity of 425 Mb/d and could be in-service by 2012, pending regulatory approval.

Enbridge had announced in 2008 that it planned to re-reverse Line 9 to transport western Canadian crude oil to refineries in Montreal, eastern Canada, and allow exports to the northeastern U.S. and U.S. Gulf Coast. The capacity of the Trailbreaker project would be 230 Mb/d and initially the in-service date, pending regulatory approval, was mid-2010. It announced in January 2009 that, due to a lack of commercial support, the project has been put on hold.

Kinder Morgan announced that it plans to loop the Trans Mountain system back from Hinton, Alberta to Edmonton, adding about 80 Mb/d of capacity by 2012 (TMX2). Kinder Morgan also has plans to further expand the Trans Mountain Pipeline, adding about 300 Mb/d to Vancouver and Washington State (TMX3) by 2011. That would put the capacity to the west coast at 700 Mb/d. Kinder Morgan also has a proposal called the TMX Northern Leg that would enable it to serve markets in California and Asia. The pipeline would have a capacity of 400 Mb/d and extend from a point near Rearguard, BC to Kitimat, BC. Depending on shipper support and regulatory approval this pipeline could be in service by 2012.

In the Fall 2008, Enbridge indicated there has been renewed interest in its Gateway pipeline project. It has raised $100 million from western Canadian producers and East Asian refiners. The company has said that it plans to file an application with the NEB in the middle of 2009. The Gateway Pipeline would transport 525 Mb/d of crude oil from Edmonton to Kitimat, BC where it would be loaded onto very large crude carriers (VLCCs) for shipment to Asia or the west coast of the United States. Also part of the Gateway pipeline project is a diluent line, which would transport 193 Mb/d of imported condensate from Kitimat to Edmonton. The expected in-service date is the 2014-2015 time frame.

U.S. Refining Capacity

This map illustrates the major refining centres in the U.S. showing where Canadian crude is currently delivered and the potential markets that continue to exist south of the border PADD I has a refinery capacity of 1.7 MMb/d, PADD II - 3.8 MMb/d, PADD III - about 8.4 MMb/d, PADD IV - approximately 600 Mb/d and PADD V - 3.2 MMb/d, for a total refining capacity of about 17.7 MMb/d.

PADD II has traditionally been the largest market for western Canadian crude oil, receiving about 62 percent of western Canada's crude oil exports in 2008. This market continues to offer growth potential for the future. Based on the previous slide illustrating the various pipeline proposals, however, the biggest growth market is PADD III, as reflected by the number of pipeline proposals to tap this market.

There are a number of factors that bode well for additional deliveries of Canadian crudes into PADD III. In the shorter term, US Gulf Coast production is down by 150 mb/d due to Hurricane Ike, the US drilling rig count is down by 12 percent, and OPEC cutbacks disproportionately affect heavier crudes. In the longer-term, Mexico and Venezuela have traditionally been exporting their heavier grades to refineries along the US Gulf Coast, but Mexican production is declining sharply, and Venezuelan heavy oil production is also in decline.

Although not shown on this slide, the previous slide pointed out that both Enbridge and Kinder Morgan have proposals to tap potential markets in California as well as Asia.

Natural Gas Supply

I'm being very careful here so as not to preempt our next presenter, but I do have some brief comments on some pipeline proposals and some recent analysis the Board has released on gas potential in Saskatchewan.

Ultimate Potential: Conventional Gas

This slide shows Canada's hydrocarbon basins, with resources of gas estimated for each. The total, 520 Tcf, is reported in our Saskatchewan Ultimate Potential report which was released last November.

You will note that more than half of the conventional gas resources from the WCSB have been produced, with most of the remainder being, as of yet, undiscovered resources. The undiscovered gas is expected to be located in shallower zones or in relatively small deeper pools, which will require significant drilling to exploit.

Nonetheless, Canada has a sizeable endowment of natural gas resources for future use. Of course, the economics to develop some of these areas will be challenging.

Regarding unconventional gas resources, across the scenarios in the Energy Futures analysis we considered 26 to 50 Tcf for Coal Bed Methane, 13 to 26 Tcf for tight gas, and 5 to 13 Tcf for shale.

Mackenzie & Alaska Gas Pipelines

Regarding the northern pipeline proposals:

In January 2008, Alaska Governor Sarah Palin 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. In December, TransCanada was awarded a license to build the pipeline. TransCanada is now preparing for an open season, to line up shippers for its proposed line. It should be noted that TransCanada is still competing against another northern pipeline proposal, the Denali Pipeline, backed by BP and ConocoPhillips

In any event, Canada is ready to deal with any filing with respect to a proposed pipeline in Canadian land to carry Alaskan gas to North American markets. NEB staff remains in touch with people potentially interested in regulatory process related to Alaskan gas. Relationships with key players have been built and will continue to be built. We remain ready.

I can't say much about the Mackenzie Gas Project because the proceedings are ongoing. The full details of the recent federal government announcement regarding financial support are not yet available. I will simply refer to the 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.

Emera Brunswick Pipeline

Meanwhile, in Atlantic Canada, the energy infrastructure continues to evolve.

The Emera Brunswick pipeline, which the NEB approved in 2007, is about to be open for service. Recently, the NEB granted Repsol Canada a licence to export natural gas, to be received by LNG tankers in Saint-John, New Brunswick, to US markets. Therefore, in the near future, we will have an additional capacity of 500 MMcf/d of natural gas available to transport LNG supplies to Atlantic Canada and US Northeast markets.