July 2015 

Stronger resilience to lower oil prices in Canadian offshore than shale


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"Comparing Canadian oil sands, shale and offshore cost curves"


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While FID on the Pacific NorthWest LNG project (operated by Petronas) is still pending, other important events have occurred over the last quarter in British Columbia, with a potential to shape the future of the LNG exports from the province. On July 1, 2015, Quicksilver Resources received approval from the National Energy Board of Canada to export 20 million tons p.a. of LNG from Campbell River, for a period of 25 years. In addition, during April 2015, Apache exited from the Kitimat LNG, and Woodside Energy International acquired its 50% share in the project. This can represent a positive sign for the future of LNG in the province; given the fact that Woodside has decades of LNG operating experience in Australia.

The New Democrat Party (NDP) elected in Alberta in May 2015 has announced a new carbon tax, which increases the fees for the heaviest carbon emitters. According to the NDP government, the carbon levies will double by 2017, from 15 CAD/tonne to 30 CAD/tonne by 2017.

The LNG landed prices have followed the declining trend of the oil prices and have fallen to 7.6-7.85 $/MMBtu at the Asian east coast. This is only ~3 times higher than the LNG price in North America. Rystad Energy expects that this could further postpone the FID for LNG export projects in British Columbia.




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NASWellData: Listing of official well data for key plays in addition to estimates for average well curves for selected acreages, NOW AVAILABLE in CUBE BROWSER.


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The decreased commodity prices hit the Canadian upstream business hard, which is effecting future contributions from shale, oil sands and offshore projects. The following elaborates on the influence of the oil prices on the Canadian shale and offshore activities, comparing the cost curves for these two important supply sources.

In general, we can observe a strong seasonality in the number of horizontal rigs in Canada mainly due to weather effects, e.g. frozen soil allows for easier drilling of wells around February, when the number of rigs usually peaks (Figure 1 excludes the SAGD rigs). After November 27, 2014, when OPEC decided against a reduction in the liquids supply, the Canadian rig market responded immediately, with a higher-than-usual winter drop followed by weak months of January and February 2015, where the usual peak of rigs did not occur. At the maximum, there were 150 horizontal oil rigs in Canada in January 2015, a 40% decrease compared to the peak in 2014. At its lowest, in May 2015, the oil rig count stood at only seven horizontal rigs in Canada drilling for liquid-rich shale. We can observe that the gas rigs are more resilient.

Rystad Energy estimates that in 2020 there is a potential for ~620 thousand barrels per day of oil production (crude & condensate) from the currently awarded shale acreage in Canada. That is comparable to the estimated oil production from Niobrara and Woodford Shale combined, in 2020. In Canada, most of these volumes are represented by liquid-rich areas in Montney and Duvernay plays, as well as oil-bearing shale plays such as Cardium and Bakken (Saskatchewan). Figure 2 depicts the cost curve for the potential 2020 oil production and the breakeven price for each shale acreage that will contribute to this production. Almost 80% of the potential 2020 production has a breakeven price below the current Brent oil price of 57 USD/bbl (as of July 8, 2015). However, the shape of the cost curve is not flat and high end exists.

Comparing shale activity in Canada with the offshore, we notice a stronger resilience in offshore Canada regarding the response to the lower oil prices. Operators with large market caps such as Statoil, BP, ExxonMobil and Shell are still actively engaging in exploration in the area, and more operators may follow suit. Statoil and ExxonMobil are expected to invest in further exploration in the Flemish Pass Basin, while BP and Shell are focusing their exploration efforts in Nova Scotia, where they were awarded several license blocks in 2012/2013. The current offshore oil production in Canada is in a natural decline as depicted on the Figure 3. However, we expect a reverse trend from 2017 onwards, when Hebron comes online. By 2020, we estimate ~270 thousand bbl/d of oil from offshore Canada, the province of Newfoundland and Labrador. All of Canadas offshore gas production is from the Nova Scotia province.

As Figure 2 suggests, all currently producing projects (Hibernia, White Rose, Terra Nova, Amethyst North) have a breakeven price below the current Brent oil price. Hebron, which is currently under development, has a breakeven of about 60 USD/bbl. Only ~5% of the total estimated 2020 oil production from Canada offshore has a breakeven price above 60 USD/bbl; all of these contributions are represented by not-yet-sanctioned discoveries. Over 95% of all offshore oil production in Canada is produced in the shallow water (up to 125 meters). We expect the deep water contributions (125-1500 meters) to increase significantly from 2025 onwards, after the new discoveries (Bay du Nord, among others) come online. Rystad Energy believes there is also a long-term potential from the ultra-deep water in Canada (above 1,500 meters), primarily in the exploration licenses in the Scotian Shelf and in the Orphan Basin Offshore Newfoundland.