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Oil Sands Producers Set to Become More Competitive

Next-generation solvent technology is lowering costs, and the long-term impact could be immense.

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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 $55 per barrel of West Texas Intermediate, our midcycle 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 and require in situ extraction; steam-assisted gravity drainage is the most common method. The SAGD process involves 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. After separation, the bitumen is cleaned while the water is treated at a water treatment plant and recycled back to the steam generation plant (recycle rates are 80%-90%). 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. Less than 20% of Canada’s oil sands reserves are close enough to the surface (less than 75 meters) to be extracted by surface mining. Vegetation, water, and upper layers are removed from the land area before bitumen is extracted with excavation machinery. Extracted bitumen is transported to a processing plant using trucks. Generally, operating and capital requirements are higher for mining projects because of the intensive machinery and labor 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
Oil sands projects have long been characterized by high capital requirements and production costs. While SAGD projects require substantial energy and water use, overall production costs still compare favorably with those of mining projects. Even though costs have declined considerably since 2014, most brownfield expansion projects are still not economical at $55/bbl WTI. The WTI break-even price required to pursue SAGD brownfield expansion projects has declined 25% to $60/bbl from 2014 requirements of $80/bbl. 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. Greenfield 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 $70/bbl WTI.

Mining projects have enjoyed similar success in cost reductions over the past two years. By our estimate, brownfield mining break-evens have declined to approximately $60-$70/bbl WTI from $85-$90/bbl WTI in 2014. As with SAGD projects, we expect cost reductions to be modest from here; it’s unlikely that all-in costs for brownfield projects can fall much below $60/bbl, if at all.

Few Expansion Projects Likely to Be Sanctioned Using Traditional SAGD
Oil sands expansion projects represent a marginal source for oil supply. Because of the high positions on the supply cost curve, many projects that were being considered when oil was $100/bbl can’t be justified at $55-$65/bbl prices.

In this new environment, brownfield SAGD projects hold the best opportunity for sanctioning in the near term when WTI is again north of $60/bbl. But oil sands expansion projects require tremendous amounts of up-front capital, at CAD 25,000-100,000 per flowing barrel (CAD 30,000 per flowing barrel at a 50,000 bbl/day project equates to CAD 1.5 billion in initial capital outlay). Given this and the uncertainty as to what oil prices will be 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 (with  MEG Energy (MEG) the obvious exception) 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 $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?
Of the possible ways to reduce costs, it appears that oil sands operators have finally picked their horse to bet on: solvent-assisted SAGD. On the basis of our analysis of the technology and its success in pilots to date, we think there is a very real cost-reduction opportunity here, although commercial implementation is probably a few years away. Other technological advances such as combustion or electrical heating exist, but their cost-reduction potential remains less proven.

One of the most attractive elements of SA 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, with some pilots using temperatures as low as 60 C. 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%. The introduction of solvents displaces a significant amount of water and thus requires less natural gas for heating. This has a trickle-down effect that lowers other oil sands costs. Brownfield expansion projects require less-extensive water treatment, steam, and power generation plants--all of which reduce the up-front capital requirements. 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.

Further lowering break-even costs are increased field recovery rates. Since less steam is needed to dissolve the bitumen, SA SAGD wells can pump additional bitumen from the reservoir, replacing much of the condensed steam accompanying current SAGD production. As a result, fewer wells are needed to reach nameplate production capacity, which reduces annual sustaining well pads, routine maintenance and repair, and operating workforce.

Even though solvents are purchased for the extraction process, most of the costs are passed through upon selling the blended product. The same solvents are sold back to the market in the form of the blended product. Therefore, an additional cost layer is not added to the extraction process.

Also, 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%-10% of total greenhouse gases contained in a barrel of bitumen are emitted during oil sands extraction and production, which amounts to approximately 0.05 ton of carbon dioxide equivalent/barrel of oil equivalent of in situ production and approximately 0.07 ton of carbon dioxide equivalent/boe of mining production. The government’s proposed plan would tax CAD 10/ton of carbon emitted in 2018, rising by CAD 10/ton a year until it reaches CAD 50/ton in 2022. Based on current carbon emissions, the tax could add CAD 0.45-2.30/bbl to the existing SAGD cost structure. We expect the implementation of SA SAGD technology to lower carbon emissions approximately 25% and reduce incremental costs to CAD 0.35-1.70/bbl. 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%-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 on contracted take-or-pay contracts are lower.

Currently, oil sands producers use 25%-50% of a barrel of condensate for every barrel of bitumen extracted to ensure it meets pipeline specifications. Thus, a significant portion of the limited Canadian pipeline takeaway capacity is filled by blending agents. Additionally, most shipping contracts are fixed take-or-pay contracts, and shipping costs don’t vary with actual volumes shipped. Blending rates in the SA SAGD process are lower because many of the heavier metals are left in the ground. We expect 5%-20% of a barrel of solvent to be used in blending the extracted bitumen, while the remaining 80%-95% will be recycled and used for further extractions. Because the blending rate is lower in the SA SAGD process, we expect more bitumen and less condensate and solvents to be shipped on the existing pipelines.

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)/(CVE) has been operating a solvent-based pilot at its Christina Lake project for almost five years. The company has tested several solvents, with no significant difference in performance. To date, the pilot has operated with 30% lower steam/oil ratios, 10% lower sustaining capital and nonfuel operating costs, and lower emissions, water use, and land footprint. The pilot has also experienced a 15% increase in field recovery rates and solvent recovery rates (recycle rates) in excess of 80%.  Imperial Oil (IMO)/(IMO) is operating a small pilot at its Cold Lake project, which commenced in 2010, and has produced similar results. Like Cenovus, Imperial is testing different solvents, resulting in similar operational performance.

Alternatively, MEG Energy is using co-injection of noncondensable natural gas at its Christina Lake SAGD project, called Enhanced Modified Steam and Gas Push. To date, eMSAGP operates with 50% lower steam/oil ratios, 10% higher field recovery rates, and lower per-barrel operating costs (operating costs are lower as fixed costs are spread over the increased production).

Additional solvent-assisted production methods are being tested that could eliminate water use altogether. An example is  Suncor Energy’s (SU)/(SU) 300 bbl/d 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%.

While SA SAGD is expected to lower costs and greenhouse gas emissions, it’s 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 in situ extraction method for future expansion projects. Companies have been encouraged by the pilot results so far and are ready for large-scale use. Reductions in capital expenditures and operating and transportation costs, coupled with increased oil quality, should help oil sands projects compete with other marginal supply sources.

As a result, we expect SA SAGD to improve producers’ cost structures and overall WTI break-even prices required to sanction in situ expansion projects. We forecast average brownfield break-even prices to decline over 15% from today’s prices to $50/bbl WTI, which allows producers to be competitive with other marginal supply sources. Meanwhile, mining projects continue to be on the back burner as new technology has been focused on SAGD recovery improvements.

Using SA SAGD technologies, certain greenfield expansion projects with concentrated reservoirs also possess favorable economics. However, not all greenfield expansion projects are created equal, and it’s unlikely that all projects will possess such favorable economics. As such, we forecast the average WTI break-even prices of $50/bbl on greenfield expansion projects with concentrated reservoirs.

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 $55-plus oil prices as SA SAGD expansion projects are likely to be larger-scale than current modular growth projects. Once sanctioned, first oil isn’t expected for approximately three years. During the three-year period, construction consists of specialized injection wells that co-inject solvents with steam, coupled with new central processing and water treatment plants that incorporate the impact of solvents in the extracted products. Furthermore, the reservoir needs to reach the desired heated temperature before bitumen can flow to the surface. Once ready for extraction, the initial ramp-up period can last 12-24 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.

Certain producers are better positioned than others to implement the new technology. However, the operational similarities of SA SAGD and SAGD allow for producers that haven’t invested in pilots to use the technology, albeit later than the SA SAGD first movers.

MEG appears to be one step ahead of its peers with its eMSAGP operations, which are already paying off in the form of lower maintenance capital and operating costs. We expect the company to continue implementing its eMSAGP technology on its Christina Lake brownfield expansion projects beginning in 2017. However, we believe Imperial and Cenovus are in the best position to implement solvent-based technology on future expansion projects. Both companies intend to use SA SAGD on greenfield expansion projects and hold the potential to use the method on future brownfield expansion projects as well.

Husky Energy Our Top Pick
 Husky Energy (HUSKF)/(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 in when oil prices are low. Husky’s downstream and midstream operations should not be overlooked, accounting for about 30% of the company’s EBITDA. In addition, Husky’s integrated operations help mitigate market volatility by generating cash flow when commodity prices are low.

The company continues its strategic transition toward low-sustaining-capital production, with sustaining capital costs approximating CAD 6/bbl. 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 of sub-$35/bbl Brent (excluding overhead costs) at current production levels, which compares favorably with peers.

Additionally, concerns about natural gas production in China appear overstated, despite causing repeated meaningful share price moves. Although Husky came to a favorable 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.

Joe Gemino does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.