Oil sands projects have long been characterized by high capital requirements and production costs. Even though production costs have drastically decreased over the past two years, most expansion projects still aren't economic at US$55 per barrel of West Texas Intermediate (our mid-cycle forecast) and struggle to compete economically with other global supply sources. And there is little room to reduce costs further with current extraction methods.
In the search for lower costs, producers have spent considerable time and resources on testing new technology. For oil sands producers, that research has paid off in the form of solvents. Solvent-assisted technology should provide producers with the cost savings needed to be competitive with other marginal supply sources (deep water and higher-cost U.S. shale, for example). However, commercial implementation of solvent-assisted technology is not expected for at least a few more years as low oil prices continue to constrain expansion investment decisions and project development timelines are lengthy.
Oil sands basics
About 80% of Canada's oil sands reserves are too deep to be extracted by mining techniques. Steam-assisted gravity drainage (SAGD) is the most common method, involving two horizontal wells drilled into the oil sands reservoir. Steam is injected into the upper well, heating the reservoir to temperatures as high as 200 degrees Celsius and melting the bitumen. The second well pumps the heated bitumen and water emulsion to the surface.
SAGD oil sands projects require substantial amounts of energy and water to extract the bitumen as well as chemicals to clean and separate the bitumen and water. The costs of chemicals used in the oil and water cleaning and treatment processes represent as much as 15% of SAGD production costs, while energy costs represent as much as 40%.
On the other hand, mining projects face more challenged economics, and this form of production faces a much grimmer future in a lower-for-longer oil price environment. Generally, operating and capital requirements are higher for mining projects because of the intensive machinery and labour requirements needed to clear the land, coupled with bitumen becoming more difficult to extract the deeper it is.
Low-hanging fruit is running out, and break-evens are still high
Production costs for most brownfield SAGD expansion projects have declined considerably since 2014, from US$80 per barrel in 2014 to US$60 today. Cost reductions have been driven by the weakening of the Canadian dollar, leveraging of existing infrastructure, workforce reductions, drilling cost and contract rate reductions, and maintenance optimization.
We expect that most of the cost improvements have already been realized. Companies are operating with lean workforces, have already renegotiated drilling and contract rates, and are stretching infrastructure to as many projects as possible. As such, we believe further cost reductions will be modest, and brownfield SAGD break-evens using current production processes are unlikely to fall meaningfully further in the coming years. Based on the infrastructure in place and contract negotiations with drillers, we believe producers cannot meaningfully lower costs without revamping the entire extraction process. New SAGD projects face even more challenged economics (requiring additional infrastructure such as water treatment plants, blending facilities, and regional pipelines), with project break-even prices that exceed US$70 per barrel.
Few expansion projects likely to be sanctioned using traditional SAGD
Oil sands expansion projects represent a marginal source for oil supply. Because of their relatively high costs, many projects that were being considered when oil was US$100 can't be justified at US$55-US$65 prices.
In this new environment, brownfield SAGD projects hold the best opportunity for sanctioning in the near term when WTI is again north of US$60 per barrel. But oil sands expansion projects require tremendous amounts of up-front capital. Given this and the uncertainty over future oil prices in the longer term, we expect very few projects to be sanctioned and brought on line once the current project queue has been completed in 2017.
The good news for Canadian producers is that low or no growth in the medium term will leave them with strong financial positions. Most of the oil sands producers have strong balance sheets and will have much lower growth capital expenditures in the coming years. This will make the major Canadian producers free cash flow positive in a US$55-plus oil price environment over the next few years. If oil sands costs become more competitive or oil prices rise, the major Canadian firms will be in a strong position to deploy capital aggressively to expand production.
Can SAGD reduce costs to be more competitive with other supply sources?
One of the most attractive elements of solvent-assisted SAGD is how little it differs operationally from current SAGD production processes. Instead of injecting only steam into reservoirs, SA SAGD wells inject a combination of steam and solvents (such as condensate, butane, methane and propane), reducing the amount of natural gas and water needed in the heating process. The mixture of solvents and steam is pumped into the reservoir at much lower pressures and temperatures than traditional SAGD. Solvents dissolve in the bitumen, which lowers its viscosity and increases its porosity, allowing it to flow to the surface at lower temperatures.
SA SAGD production can lower costs…
The biggest benefit of SA SAGD is that it meaningfully lowers the energy intensity of oil sands production, which we believe can cut energy costs and water use by as much as 25%. This has a trickle-down effect that lowers other oil sands costs: projects require less-extensive water treatment, steam and power generation plants. The reduction in water use also reduces the plant operating expenses associated with cleaning the extracted bitumen, separating the extracted bitumen and water emulsion, and chemical costs associated with treating the reduced water.
It's worth noting that the Canadian government is establishing limits on greenhouse gas emissions and raising carbon taxes. While oil sands extraction is associated with a high carbon footprint, only 7% to 10% of total greenhouse gases contained in a barrel of bitumen are emitted during oil sands extraction and production. We expect the implementation of SA SAGD technology to lower carbon emissions approximately 25% and reduce costs stemming from carbon taxes. As these costs aren't significant to the cost structure, we believe concerns about the emissions tax are overblown.
…and improve quality
SA SAGD extraction methods produce higher-quality, less viscous oil, which should improve bitumen price differentials by as much as 10% to 15%. The solvents-based approach dissolves bitumen in the reservoir, and because of the lower pressure and temperatures, heavier metals that accompany today's SAGD production, such as sulfur, are left in the ground. The economic benefits of this are twofold: production is pipeline-ready or nearly so, and the fixed transportation costs of shipping more bitumen are lower.
Progress to date
Multiple SA SAGD pilot projects have been in operation for several years, and in general the results have been very encouraging. 
Cenovus Energy (CVE) has been operating a solvent-based pilot at its Christina Lake project for almost five years. To date, the pilot has operated with 30% lower steam/oil ratios, 10% lower sustaining capital and non-fuel operating costs, and lower emissions, water use and land footprint. Imperial Oil (IMO) is operating a small pilot at its Cold Lake project, which commenced in 2010, and has produced similar results.
Additional solvent-assisted production methods are being tested that could eliminate water use altogether. An example is Suncor Energy's (SU) 300-barrel-per-day pilot of its partner Nsolv's technology at Suncor's Dover test site. The pilot has been operational since 2013. Nsolv's solvent-assisted technology aims to cut energy use and greenhouse gas emissions by as much as 75% from current SAGD technology by completely eliminating water use. By our estimates, this could lower the company's in situ break-evens by approximately 20%.
SA SAGD is not without risks. The technology relies heavily on solvents, which can be expensive. Condensate, which is currently used in blending and transporting oil sands production after it's extracted, often trades at a premium to light crude oil. However, SA SAGD can use different solvents, allowing the producers to use the lowest-cost option. While solvents are purchased for the extraction process, the same solvents are sold back to the market in the blended product. Therefore, an additional cost layer is not added to the extraction process.
Broad implementation still a few years away
We expect SA SAGD to become the most commonly used extraction method for future expansion projects. Companies have been encouraged by the pilot results so far and are ready for large-scale use. Meanwhile, mining projects continue to be on the back burner as new technology has been focused on SAGD recovery improvements.
Commercial implementation of SA SAGD is still a few years away, though. Producers aren't expected to make investment decisions until 2017-18 at the earliest on the best SA SAGD projects. And producers aren't expected to begin construction until there is proof of sustained US$55-plus oil prices. Once sanctioned, oil isn't expected to flow for approximately three years. Once ready for extraction, the initial ramp-up period can last 12 to 24 months. With SA SAGD implementation so far out, we expect producers to continue to use SAGD extraction in the near term on the best projects.
Husky Energy our top pick
Husky Energy (HSE) remains our top Canadian integrated pick. While Husky is in less of a position to benefit from advanced extraction technologies, we believe that the market is unjustly punishing the company for its intended lack of large-scale growth and suspension of dividends while overlooking Husky's ability to generate free cash flow when oil prices are low.
The company continues its strategic transition toward low-sustaining-capital production, with sustaining capital costs approximating $6 per barrel. We expect production from low-sustaining-capital projects, which includes oil sands production, to grow from 8% of total production in 2010 to approximately 45% at the end of 2016. Improved efficiency on oil sands production affords the company break-even prices below US$35 per barrel of Brent crude (excluding overhead costs) at current production levels, which compares favourably with peers.
Additionally, concerns about natural gas production in China appear overstated, despite causing repeated meaningful share price moves. Although Husky came to a favourable agreement with CNOOC over price realizations for its Chinese production, there remain concerns that CNOOC will attempt to renegotiate if low prices persist. Whatever transpires from here, natural gas production from China represents only 7% of Husky's total production, and additional price declines will not have a significant impact on the company's value. Furthermore, free cash flow growth holds the opportunity for reinstatement of the dividend.
