TransCanada - Update Online Magazine

Turning the Corner: Outlook on the Western Canada Sedimentary Basin (WCSB)

April 6, 2011

It has been just over one year since TransCanada developed an information booklet on the Western Canada Sedimentary Basin (WCSB) titled WCSB Myths and Realities - A Practical Guide to the Potential of the WCSB. Looking at the developments that have unfolded over the past year, the continued belief in the ultimate potential of this basin remains.

Many factors influence a long term outlook for natural gas supply. These include the extent to which technology, fiscal/regulatory changes, cost control, gas price and competition for capital influence the revival of conventional and tight gas production and the development of emerging shale gas and shale gas/tight gas hybrid resources.

In TransCanada’s view, there have been sufficient positive developments over the past year to continue supporting the conclusions made in WCSB Myths and Realities that WCSB production will stabilize and over time increase from current levels. Four of the more positive developments are the new Alberta royalty regime, supply cost reductions, higher well productivity and robust pricing for natural gas liquids.

Alberta’s New Royalty Regime

The new royalty regime in Alberta has restored the positive investment climate that existed prior to 2008. The industry has welcomed the changes for both oil and gas development. Although the current gas prices will dampen some of the impact on drilling activity in the short term, the industry appears to be positioning itself for by securing land positions. The stability provided by the new royalty regime and the incentives introduced for shale and deep gas development, and horizontal drilling applications have strongly influenced the robust land sale activity resulting in record land sales in 2010 in Alberta.

Cost Reduction

Overall WCSB supply costs have come down since they peaked in 2008. According to the NEB’s November 2010 Energy Briefing note entitled “Natural Gas Costs in Western Canada in 2009”, the average supply cost for new natural gas production in Western Canada in 2009 has declined since 2007. The Western Canada average natural gas supply cost for new production decreased from $7.88/GJ in 2007 to $6.97/GJ in 2009. This supply cost reduction does not reflect the positive royalty changes that would come into effect in 2010.

The reduction in overall production costs has been primarily driven by more efficient application of drilling and hydraulic fracturing technology, as well as regulatory and fiscal improvements. For example, significant savings have resulted from allowing the co-mingling of production from different zones within the same well bore. Drilling costs in the deep basin have decreased from just under $1000/metre in 2006 to about $250/metre in 2010. Furthermore, hydraulic fracturing in 2006 typically consisted of 4 frack stages/well at $1.5 million per frack, whereas in 2010, average horizontally completed wells consisted of 14 fracks/well at a cost of $0.5 million per frack interval. The proportion of wells that are drilled horizontally has also increased significantly from 3% in 2007 to over 20% in 2010 (see Figure 1). Although horizontal drilling is not new, in combination with sequential multi-stage fracturing technology and longer horizontal legs, the economics have improved dramatically. The productivity of a horizontal well is about 4-7 times the productivity of a vertical well yet the cost of a horizontal well is only about 2-3 times that of a vertical well. For example, as seen in Figure 2, the well costs per frack have decreased almost 60% in 4 years.

A large portion of undiscovered gas resources are located in “tighter” and deeper formations. There has been an increasing trend towards drilling deeper and longer wells. Average drilling length has increased from 1200 meters to 1600 meters in one year. In combination with horizontal drilling technology, royalty incentives and regulatory changes, the economics of developing deeper, tighter formations have significantly improved.

It’s expected that costs will continue to decline as technological advances continue making strides.

Well Productivity

As a result of the dramatic shift in the type of wells being drilled, it has become more challenging to rely on historical indicator trends in drilling and well productivity to project future trends. Well productivity is a key indicator of the impact that drilling and completion technology has made in recent years. Initial productivity (IP) has been trending up and has increased significantly in 2010. The higher the productivity, the fewer wells needed to be drilled to maintain production levels. As recently as 2006, 16,000 wells would have been required to maintain production levels in the WCSB. Now, only 4,500 wells are required (Figure 3).

Rich Gas Development

The value of natural gas liquids (NGLs) in the gas stream is also assisting in maintaining production in the current environment of $4 gas prices. Ethane, propane, butane and pentanes+ have more monetary value as commodities than their heating value equivalent. This has significantly complemented the economics of gas exploration and production in key areas. Data from a November 18, 2010 presentation by Keyera shows the significant boost NGLs have in the production of natural gas. Keyera cites, for example, a well containing 20 bbls/MMcf of natural gas can enhance the netback by 23%.

WCSB - Gas Demand and Exports

The amount of gas production available for export on pipelines exiting the WCSB region is dependant not only on the level of production but also on the level of gas demand in Western Canada. Gas consuming sectors in Western Canada include electric generation, mineable and SAGD (in situ oil sands production), upgrading and other industrial, residential/commercial and pipeline fuel. Demand for gas in Western Canada is expected to increase from an annual average of 4.9 Bcf/d in 2008 to 6.9 Bcf/d by 2020.

Western Canada Demand Growth

Oil sands production is expected to be a key driver of gas demand growth in Western Canada even after considering technological advances that are expected to result in reduced gas intensity for oil sands projects. Furthermore, much of the growth in gas demand for power generation is also associated with oil sands projects. As such, most of the Western Canada gas demand growth relates to the growth in oil sands production in the region.

Western Canada Gas Exports

Gas exports from Western Canada are equal to the WCSB production level less the gas demand within the region. Since 2005, exports from Western Canada have declined from a level of approximately 12.5 Bcf/d and are forecast to bottom out at 8.7 Bcf/d in 2011. This recent reduction is mostly due to the corresponding decline in WCSB production and to a lesser extent, some growth in regional gas demand. WCSB production is expected to rebound to 17 Bcf/d and Western Canada gas demand is expected to increase to 6.9 Bcf/d by 2020, with resulting exports projected to remain in the 9 - 10 Bcf/d range through 2020.

Based on TransCanada’s expectation of WCSB demand, Figure 4 also shows the range in outlooks of WCSB exports driven by the different expectations forecasters have regarding WCSB supply recovery. The implied WCSB export forecasts of different organizations vary by a wide margin; as much as 4.5 Bcf/d by 2020.

Conclusion

WCSB production is turning the corner and recovering. The changes, including those described above, that have been taking place over the past two years are beginning to show results. If the trend continues and events unfold as expected, WCSB production levels will stabilize and eventually increase.

While gas demand in Western Canada is forecast to grow, the improved WCSB production outlook leads to an outlook for sustained levels of Western Canada gas exports consistent with TransCanada’s view that the WCSB will continue to be a reliable and competitive source of natural gas for North American consuming markets.