With the release of GLJ’s April 2020 commodities price forecast, all eyes were on the unprecedented crash in crude oil prices, driven by the global economic slowdown due to the COVID-19 pandemic and simultaneous oil price war initiated by Russia and Saudi Arabia. As a result, the GLJ Q2 2020 forecasts for WTI and Brent fell to $30USD/bbl and $34USD/bbl from our January 2020 forecast of $61USD/bbl and $67USD/bbl, respectively. Long term both WTI and Brent prices are forecast to remain suppressed as economic recovery is expected to be drawn out with oil supply continuing to outpace demand, regardless of agreed upon production cuts announced in April by OPEC+ partners. This impact was magnified on April 20, 2020 when WTI prices plummeted into the negatives.
On the other hand, one could hardly be blamed for quickly glancing over the local gas price forecasts which experienced a much smaller drop:
This begs the question - why has the price drop for natural gas; and AECO specifically, been so much less than oil? One would reasonably expect the unprecedented and indiscriminate global slowdown due to COVID-19 would affect all aspects of industry equally. In fact, short term strip prices (futures vs. strip pricing refresher) at AECO have actually improved since March 31:
One of the reasons for this muted price drop is the Canadian oilsands, which make up more than 25% of natural gas demand in Canada. SAGD and CSS recovery processes utilize steam injected into sub-surface oil deposits to warm up the reservoir, thereby reducing bitumen viscosity, facilitating flow to the surface through production wells. Natural gas is the primary source of energy used by the steam generating turbines that are crucial to this process. In essence, natural gas is indirectly exchanged for oil by converting its chemical energy into thermal energy that gets transferred by the steam and allows the oil to flow.
*Market Snapshots, Canada Energy Regulator
Given their long producing life and near flat production profiles the oilsands provide a steady base demand for natural gas in Canada. After significant initial capital investments, in-situ bitumen extracting assets require a ramp up phase lasting one to two years, in which steam is gradually injected until the desired steam chamber is established in the reservoir and long-term steady state SOR (steam-oil ratios) are reached. A delicate balance must be found during this process as different steam injection pressures induce different reservoir geomechanical effects; ultimately affecting reservoir permeability, long term deliverability, and cap-rock integrity.
*Steam Assisted Gravity Drainage (SAGD) Scheme, Energy Resources Conservation Board
Industry opinion regarding production outages has slowly shifted over the years where initial beliefs were that any sustained shut-ins could cause potentially significant reservoir damage due to collapsing steam chamber, bottom water influx and even ESP failures as the bitumen slowly starts reverting to its original, more viscous, form. As operators have gone through numerous plant turnarounds with shut-ins lasting for weeks and even unplanned emergency curtailments such as the Fort MacMurray wildfires in 2016, the operational mitigation of these problems has steadily improved; especially in mature assets.
In-situ oilsands projects are generally resilient to short-term pricing disruptions with their long-term production profiles and price hedging contracts, but given the magnitude of the oil price crash and supply/demand disconnect, most operators including Cenovus Energy, Husky Energy, and ConocoPhillips are curtailing production; reducing throughputs and pumping reduced steam rates. We have not seen major demand reductions to date but operators may be forced to take unprecedented actions and either moderately or even significantly curtail thermal production. To date only Athabasca Oil Corps 9,500 bbl/d Hangingstone asset has been completely shut-in. Additionally, oilsands mining, which uses comparatively less natural gas as a feedstock, will see equivalent production cuts with Suncor Energy and Teck Resources already announcing the closure of one of the two production lines at their Fort Hills site which can produce 194,000 bbl/d, and Imperial Oil evaluating curtailment at its Kearl Mine capable of over 200,000 bbl/d.
GLJ expects near-term expansions will be delayed and the focus from operators will be continuing to find production efficiencies and reducing operating costs. As the oil market rebalances and prices recover, so will oilsands production, restoring their associated natural gas demand:
As the transition to a sustainable energy future continues GLJ expects natural gas to play a leading role in the transitory phase where it’s demand will significantly increase. This will primarily be driven by the abundance of natural gas, it’s lower GHG emissions, and the phasing out of coal-fired power generation. The oilsands will continue to be a key driver of industrial natural gas demand in Canada, and cogen (the simultaneous production of electricity and thermal energy that would otherwise have been lost) will continue to develop in step as ESG becomes an even bigger factor in future projects.
*Canada’s Energy Future 2019, Canadian Energy Regulator
For further reading on the fundamentals of Natural Gas pricing in Canada, stay tuned for future blog posts on the future of LNG in Canada and the effect of reduced shale drilling south of the border.
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