“The oil sands don’t get enough attention, and when they do, it is the wrong attention,” said Mark Oberstoetter, director of research in Calgary, Alberta, for Wood Mackenzie. “There is the perception that it is a high-cost basin, but some projects have operating costs as low as C$7 a barrel. Some are higher, but several are at less than C$10. That is definitely a factor, even if capital costs can be in the middle or at the high end.”

Oil sands extraction is roughly divided evenly between mining operations and in situ, where the prevailing process is steam-assisted gravity drainage (SAGD). WoodMac figures show that SAGD operating costs have dropped in the past few years from about C$15 a barrel to C$10 or below. Mining-based operations have seen an even greater improvement, from operating costs as high as C$40 to the mid-C$20s.

Combined output from all three Jackfish fields averaged 125,100 barrels per day through first-quarter 2017. (Photo Courtesy: Devon Energy Corp.)

The other key point that Oberstoetter stressed is the decline curve, or rather, lack of one. “This is not like other oil and gas development where you drill a well and watch it decline. This is more like manufacturing. You have the up-front cost of building a plant, but then it produces for 20 years at cost of goods and maintenance. SAGD operators are doing what they can to drive down costs and steam-oil ratio (SOR). That also reduces the environmental footprint, so everyone is happily aligned.”

Nathan Nemeth, a research analyst for Canadian upstream at WoodMac, pointed out that Devon Energy Corp.’s SOR at its Jackfish operation was planned for 3 and is actually operating in the mid-2s, meaning there is excess steam that can be applied to new wells for the cost of drilling and connection, with no new capex. “That is how they are able to be producing 20,000 barrels per day over design capacity,” he said.

To drive SOR below 2, producers are testing methods of adding propane or butane to the steam as a solvent. “That is the next big thing,” said Nemeth. “You need to reach 90% solvent recovery to make it economical, but you increase the API gravity of the bitumen from about 8 to about 12.”

To put oil sands into perspective, Nemeth said, “If you told a Permian operator that he could drill a well that would make 1,000 barrels per day with no decline for five years, that would be the first well he would drill. The catch is that he has to spend $US100 million up-front first.”

Devon’s first commercial SAGD facility, Jackfish, achieved first production in 2007. (Photo Courtesy: Devon Energy Corp.)

It will surprise few that 30% of Devon’s projected 2017 estimated cash flow of about $2 billion is expected to come from the Eagle Ford, heavy oil is expected to generate an even greater amount—35%—of that free cash. The company’s high-profile positions are in the Eagle Ford, Stack and Delaware Basin, but for the bottom line, the star is to the north.

In 2016, Devon Canada’s heavy oil net production comprised134,000 barrels of oil equivalent per day (boe/d), 98% liquids, or 22% of company liftings. That was primarily from the Jackfish SAGD oil-sands operation in Alberta, which turns 10 this year. There are also cold-flowing wells at Lloydminster. At the end of last year, heavy oil reserves were booked at 504 MMboe (99% liquids), 24% of the company’s total reserves.

Combined output among all three Jackfish operations averaged 125,100 bbl/d through the first quarter of 2017. That represents a sharp jump of 23% over production in first-quarter 2016 and is a healthy 20% better than the 105,000-bbl/d nameplate capacity.

Inexpensive vs. U.S. unconventional

“When we look at the monthly results, Canada is No. 1 for free cash,” Rob Dutton, president of Devon Canada, told Investor. “It’s about a quarter of the production on a boe basis, and 30%-plus of cash flow. Operating expenses have been material to that. There are many factors that have gone into that, not the least of which is our service providers have certainly sharpened their pencils. There are also structural things, chemical use and new technology. Taken together, they have all helped margins.”

Dutton stressed that the two most important points about oil sands are the very low cost to convert reserves into production, and the extremely long life once in production. “It is true that there is a heavy capex at the start of a SAGD project, but after that, the cost to convert a barrel from proven to producing is only about C$4 to C$5. That is very inexpensive if you look across other plays, notably U.S. unconventional.”

In a similar vein, he noted, “We have a great deal of reserves booked. Those will be in production for 20 years or more. That is the real value when you can maximize the output of your central processing facility. Keeping those plants full for 20 years is very competitive on a per-barrel basis. When people get caught up in ‘margin’ they miss the importance of cost-to-flow and sustained production. Longevity, stability and low-sustaining capital all combine to make the life-cycle rate of return very competitive.”

"SAGD operators are doing what they can to drive down costs and steam-oil ration (SOR)," said Mark Oberstoetter (left), director of research at Wood Mackenzie. "Producers are testing methods of adding propane or butane to the steam as a solvent to drive SOR below two," according to Nathan Nemeth (right), research analyst for Canadian upstream at Wood Mackenzie.

Most operators and analysts confirm that the SOR is the essential metric and a strong indicator of profitability for the SAGD process. There is variability in oil sands just as there is in shale, but the top-performing SAGD wells are reporting SOR of about 2.3, or 2.2 to 1.

New extraction methods are driving that number even lower. The closest to commercialization involves blending solvent with the steam. Pilot projects have reported solvent-assisted SORs of less than 2. Like frack fluids, the basic components are well-known, but every company has its own secret recipe. Propane and butane are common solvents, in contrast to C5s or natural gas that are often used as a diluent for rail or pipe transport.

In the past few years, the industry has collaborated on extraction technology research, forming Canada’s Oil Sands Innovation Alliance. “That collaboration is new,” said Dutton. “We have some of the best SORs, but we are still looking at options. That said, I caution people who bandy about the idea of solvents as if it is proven; it is not yet. It is a part of the future of SAGD, but at what stage is it best to apply? What formula? There are myriad questions, and it is prudent to study each one. The underlying factor is the rock.”

The industry is investigating other technologies as well. Dutton noted that Devon Canada and Suncor Energy Inc. are studying microwave melting of the in-situ bitumen. “That has an SOR of zero,” he quipped. “Non-condensing gas is another technique and is already in use at Jackfish as well as other by operators in the oil sands. The different solvent technologies being tested are exciting but very complex and are not well-served by being taken as ready now.”

"When we look at the monthly results, Canada is No.1 for free cash," said Rob Dutton, president of Devon Canada.

Getting there is half the fun

‘Not quite ready’ could also be the caution label for transportation. For all the effort oil-sands producers put into getting the resource out of the ground and to markets, takeaway is yet a further challenge. Whether it is pipe to the U.S., pipe to the Pacific coast of Canada or rail anywhere, all of the options have at one time been controversial.

That is not likely to change, but Dutton remains sanguine. “I am more optimistic now than I have been in the past 12 to 18 months on transportation. I am confident that the expansion of Kinder Morgan Trans Mountain [pipeline system] will get built. It is important to all Canadians and our trading partners that we have access to markets. We believe we have a long-term sustainable business in the oil sands that will be an important part of the energy market for many years.”

Several oil-sands producers are generating free cash, according to Norman MacDonald, a portfolio manager for Invesco Energy Fund. “That is the number that matters when comparing the play to U.S. unconventional development.

“There are Permian and Eagle Ford operators touting internal rates of return of 60% to 70%, but the bottom-line math is that there is no free cash flow for the investor. The oil sands are generating free cash and are returning that to shareholders in the form of dividends and stock buybacks.” MacDonald manages a total of $1.252 billion, with $653 million in the Invesco Energy Fund.

“There is a whole misconception about oil sands,” MacDonald asserted. That is not only because the extraction technology is different, but also because the capital structure is different.

“There is no question that the up-front capital is significant, but the maintenance capex after that is manageable.” Advances in SAGD are driving the operating cash costs down toward $10 to $15 per barrel, but even for surface mining, costs are drastically improved. “Some of the operators have cash operating mining-target costs of $23 to $25 a barrel this year.”

It all comes down to reserve valuations, MacDonald explained. “This is not a matter of Canadian producers vs. U.S. I own a lot of U.S. unconventional, mostly Occidental [Petroleum Corp.], Apache [Corp.] and Noble [Energy Corp.]. The rest of these companies are seducing Wall Street because the street has not done a good job of reading reserve reports. Other than a few, including EOG [Resources Inc.] and Devon, there are zero net reserve additions for most of the others. On that basis, some of the oil-sands operators like Suncor and Canadian Natural Resources [CNQ] are head and shoulders above the rest.”

Green operations

Even on the environmental front, where oil sands were once the poster children for fossil fuels, MacDonald sees progress. “I’m impressed with CNQ’s work on dry-stack tailings—eliminating water—and Suncor has done a great job of dealing with their tailings ponds.” Other notable advances include Devon’s all but closed-loop SAGD process that uses water from a saline aquifer.

In terms of operating expenses, MacDonald likes the all-in sustaining cost metric that has been well-used in the mining industry. “That is fully loaded: cash costs, plus maintenance capex, interest, depreciation and royalties. In the oil sands that is C$42 to $50 a barrel these days.”

He also noted that companies like Suncor and CNQ are selling a fully upgraded primary hydrocarbon, as compared with the conventional wisdom of people just looking at Western Canadian Select, “which is a heavy barrel looking for a refinery. Edmonton Par is WTI converted to Canadian dollars, minus C$5 for transportation.” However, MacDonald is eager for further gains from new extraction methods. “I want to see a commitment to technology spending. The size of the prize is big.”

For Macquarie Group, cash is key as well. “We look at revenue minus cash costs minus maintenance capex,” said Brian Bagnell, senior research analyst at Macquarie Group. “The all-in cash spent is to hold production flat. For the best SAGD companies, operating costs are C$9 to C$10 a barrel. For all the perceptions [of the oil sands as a high-cost play], the better producers with solid capital structures are generating free cash flow at current prices. So, if you ask if most current oil-sands production is sustainable, the answer is a definitive yes.”

However, capital considerations are paramount, Bagnell said. “You have to compensate investors for the cost of capital. If you believe that WTI won’t rise above US$55 to US$60 a barrel, then it’s unlikely we’ll see much more in the way of greenfield developments, because they’d be unlikely to generate a rate of return above the cost of capital, although economies of scale and synergies can make some projects more efficient.”

Still, he cautioned, “Consolidations in the play are not necessarily a big help to the capital structures, because in some cases producers have taken on significant debt to do them.”

Essential to growth

Bagnell is confident about the potential of solvent-assisted SAGD. “For the oil sands to grow, costs still need to come down. The easy reductions, such as labor, have already come out. New technologies, such as solvent-assisted SAGD, seem to be the likely next step for cost improvements.” However, he added that some long-term contracts for service companies or suppliers were last negotiated when crude was $100, so some revisions can be expected.

In the end, the scale of the play remains compelling, as does the prospect of level production for decades at minimal spending.

“The scope of the resource is massive,” Bagnell stated. “Developments will produce for 20 to 40 years at effectively zero decline rates. Compare that with tight oil wells, such as in the Permian, with 30% to 40% decline rates, which take a lot of reinvestment to hold flat. So, it is just a matter of short cycle vs. long cycle.”

In addition, transportation “will be a source of frustration for the foreseeable future,” Bagnell said. “Of all the plans, the Enbridge Line 3 expansion seems to be attracting the least opposition, so that might have the best chance.

“Pipelines are both the cheapest and safest way to transport crude; otherwise, we are going to have to use rail. There is tremendous rail infrastructure that got built during the last boom, but then never got used after prices collapsed. It’s all still there and can handle deliveries if necessary. Pipelines are preferable, but not absolutely necessary.”

Companies are moving from expanding to maintaining production, said Ben Brunnen, vice president of oil-sands, fiscal and economic policy for the Canadian Association of Petroleum Producers. “They are also coordinating on turns so they don’t have to compete for crews.”

Taking a step back, he noted that the oil sands is “a technology play that only came into significance in the last 15 years,” so it is still coming of age.

“Carbon footprint of oil sands has been a priority and is the next technological challenge. The biggest point is SOR. One option is cogeneration. Many producers are also looking at combination of steam and solvent. It is very hard in this capital market to invest in the scale of R&D that is required to commercialize new technologies, but once they are proven, they will be deployed across the basin. These technologies have the potential to make us the cleanest oil on the planet.”

A further regional incentive is that Alberta is expected to enact some form of carbon pricing, Brunnen noted. A cap has been proposed, and discussions about implementation are ongoing. He added that some form of output-based allocation is under consideration for oil-sands producers.

Oil sands are "a technology play that only came into significance in the last 15 years," so it is still coming of age, said Ben Brunnen, vice president of oil-sands, fiscal and economic policy for the Canadian Association of Petroleum Producers.

This brings investors back to the basic question: “With oil prices seemingly settling into a $50-$60/bbl trading range, many investors are wondering whether there is a future for the oil sands in a carbon-constrained world. The short answer is yes,” Randy Ollenberger, oil and gas analyst with BMO Capital Markets, wrote in a comprehensive February report.

“Comparing a 30-year investment in tight oil to a 30-year oil-sands project yields surprisingly similar full-cycle performance.”

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