This past week I was in the Athabasca oil sands in Fort McMurray, Alberta as a guest of the Canadian government. We toured the operations of two companies on this trip — Cenovus Energy (NYSE: CVE, TSE: CVE) and Canadian Natural Resources (NYSE: CNQ, TSE: CNQ). Each of these companies applies a different approach to processing the oil sands. Today I would like to discuss the two major approaches — surface mining and in situ production — and look at the major companies engaged in each approach.

The first part of the article is mostly a review of what was covered in this week’s Energy Letter. If you read that issue, then feel free to skip down to the section titled “Canadian Natural Resources.”

Overview

As a result of advances in the development of oil sands, Canada has the third-largest oil reserves in the world. Of the 173 billion barrels of Canadian reserves, 97 percent are in the oil sands, which are a mixture of sand, clay, water and bitumen — a very heavy oil.

Alberta’s Athabasca region is the heart of Canada’s oil sands production. Oil production in Alberta has been growing by about 170,000 barrels per day (bpd) each year, and an aggregate production increase of about 1.8 million bpd is forecast by 2022.

The surface area above Alberta’s oil sands deposits is slightly larger than New York state. Of the nearly 55,000 square miles of oil sands formation, 1,853 square miles have been identified as being close enough to the surface for mining. To date, 276 square miles have been disturbed by surface mining, and 27 square miles are under active reclamation.

Source: Government of Alberta

Surface Mining

Most of the oil sands production thus far has come from surface mining, which is feasible when the oil sands are relatively close to the surface. In order to produce oil sands from surface mines, any harvestable timber is sold and the overburden — a top layer of  peat, clay and sand 30 to 40 meters deep  — is removed and set aside for future reclamation. The oil sands are then removed from the open pit and placed in dump trucks capable of carrying loads of 400 short tons.

Truck unloading oil sands at Horizon oil sands site. Source: Canadian Natural Resources

The trucks transport the ore to a processing facility where it is dropped into a crusher, mixed with hot water, and then piped to the plant. The mixture is put into large separation vessels where the bitumen is removed in the top layer, and the bottom layer of sand and some residual bitumen is sent to the infamous tailings ponds where it will eventually be buried before the land above the tailings pond is reclaimed. The recovery rate for bitumen from surface mines is above 90 percent.

Bitumen recovered from oil sands can be upgraded through various processes to a lighter oil (syncrude), as well as to products such as naphtha, diesel, and gas oil. Alternatively, the bitumen can be mixed with a diluent like naphtha to form dilbit, which can then be transported by pipeline or rail. (Unheated bitumen has a consistency like tar, and has to be upgraded, diluted, or heated to flow).

Companies involved in surface mining of oil sands include Canadian Natural Resources (discussed in more detail below), Suncor Energy (NYSE: SU, TSE: SU), Canadian Oil Sands (TSE: COS), and Imperial Oil (NYSE: IMO, TSE: IMO). The Muskeg River mine is a joint venture between Shell Canada (60 percent), Chevron Canada (20 percent), and Marathon Oil Canada (20 percent).

In Situ Production

But the vast preponderance of future oil sands growth is expected to come from in situ (Latin for “in position”) production. As of January 2013 there were 127 operating oil sands projects in Alberta, and only 5 were mining projects. Production from both methods is expected to continue to grow, but the vast majority of the oil sands resource is too deep to be accessible to mining. Thus, most of the future production growth will be through in situ production.

Expected oil sands production growth. Source: Canadian Energy Research Institute

In situ production involves injecting steam into the ground to enable the oil to flow freely. The oil is then pumped to the processing facility. In situ production has the advantage of a much smaller surface footprint, since it doesn’t require the removal of overburden from the surface above the deposit. Nor does it require extensive tailings ponds.

There are two primary methods of in situ bitumen production. Cyclic Steam Stimulation (CSS), or the “huff-and-puff” method, was first used commercially in Alberta by Imperial Oil at Cold Lake in 1985. This technique involves the injection of steam into the formation for a period of time, followed by an extraction period in which the oil is pumped out. When the oil flow slows to a certain point, steam is once more injected. This cycle continues until the well is no longer economical.

The other in situ method is called steam assisted gravity drainage (SAGD), and it was enabled by the same sort of horizontal drilling breakthroughs that enabled the hydraulic fracking revolution. SAGD was first commercialized in 2001 by Cenovus at Foster Creek, and it was the single biggest reason that Canada’s oil reserves more than quadrupled in the past 20 years. Once a technique makes it both technically viable and economical to produce a resource, it can be placed in the reserves category. Again, this is a similar situation to fracking, where resources in places like the Bakken and Eagle Ford became reserves when fracking made them economical to produce.

SAGD involves drilling a pair of horizontal wells, one about 5 meters above the other. Steam is injected into the upper well for months to heat up the bitumen. I learned from Cenovus that their initial projects required them to inject steam for 18 months before producing oil, but as they have progressed up the learning curve the timing has been reduced to 3 months of steam injection. Producing wells have seen almost no depletion through 10 years of production (a situation very unlike fracking, which causes wells to initially deplete rapidly).

The horizontal wells can be drilled for miles in many directions from a single well pad, and as a result a large land area can be accessed without a huge environmental impact on the surface. A well pad such as the one I visited below can produce nearly 20,000 bpd of bitumen for 10 years before depletion begins to curtail production.

Cenovus SAGD well pad with nine well pairs. Source: Cenovus.

Canadian Natural Resources

One of the visits I made on my trip to Alberta was to Canadian Natural Resources’ Horizon Oil Sands Project. The project consists of surface oil sands mining, a bitumen extraction plant, and on-site bitumen upgrading that includes coking and hydrotreating operations. The product is sweet synthetic crude oil (SCO), as well as diesel, naphtha, and petroleum coke.

Aerial view of the Horizon oil sands facility. Source: Canadian Natural Resources

Horizon Oil Sands’ leases are north of Fort McMurray, Alberta in the Athabasca region. These leases are estimated to contain approximately 14.3 billion barrels of bitumen initially in place, with 2.9 billion barrels of proved and probable SCO reserves. CNR estimates that 6 billion to 8 billion barrels are ultimately recoverable. Given the scale of the resource base, the mine and plant facilities are expected to produce for decades without the production declines normally associated with crude oil.

At present, the Horizon has five expansion stages scheduled. Phase 1 aimed to deliver 110,000 bpd of fully upgraded, light, sweet, synthetic crude. That target was reached in Q3 2013, with a production rate of  112,000 bpd (a 16 percent year-over-year increase).

Phases 2 and 3 will boost output to 250,000 barrels per day, with potential for further expansion to 500,000 barrels per day. Production costs at Horizon are largely fixed, so production costs on a per barrel basis will decline significantly when Phases 2 and 3 come on-stream. Currently the cost of production is in the $40/bbl range. Capital costs add another $10-$20/bbl, but the expected operating cost for the life of the mine is projected to decline to between $25 and $35 per barrel of SCO. Not bad considering that the going rate for SCO over the past couple of years has been $90-$100/bbl.

While Horizon is a key part of CNR’s business, the company is involved in a number of other activities. It is the second largest independent natural gas producer in Canada, as well as the largest heavy oil producer in Canada. CNR’s portfolio also includes in situ oil sands and natural gas liquids (NGLs), and assets in North America, the North Sea and offshore Africa.

In the most recent quarter the company produced a total of 1.2 billion cubic feet (bcf)/day of natural gas (down 2 percent year-over-year) and 509,000 bpd of crude oil and NGLs (up 8.5 percent yoy). Year-to-date earnings through Q3 were $1.86 billion (Canadian), versus $1.54 billion for the same time period a year ago.

CNR has a market capitalization of $33.4 billion, and an enterprise value of $44 billion. The EV/EBITDA for the trailing twelve months (ttm) is 5.3. The company has a debt to asset ratio of 36.8 percent, a profit margin of 13.9 percent, and a return on equity of 8.9 percent. The current dividend yield is 2.5 percent.

Cenovus Energy

Cenovus Energy was formed on Dec. 1, 2009 when Encana Corp. split into two companies: the oil company Cenovus and the natural gas company Encana. Since the split Cenovus shares have traded mostly higher — up nearly 60 percent at one point — while Encana shares have fallen nearly 70 percent as a result of low natural gas prices.

Cenovus is one of many operators in the Athabasca oil sands utilizing SAGD. The technique has had a dramatic impact on Canada’s oil reserves by enabling the production of oil sands that were formerly too expensive to produce. One might say that Canada is experiencing a “SAGD revolution” analogous to the fracking revolution in the US.

Cenovus is a bit different from CNR in that it doesn’t upgrade the bitumen produced on site. It is typically transported to a refinery and refined into finished products like diesel, gasoline, and jet fuel. Since bitumen is a solid at room temperature, it has to be diluted or kept warm to transport. Transportation can be done via a heated rail car, but mostly the bitumen is mixed with a diluent so it flows freely, and then transported by pipeline or rail.

Cenovus has an interest in two heavy oil refineries through a partnership with Phillips 66 (NYSE: PSX), which enables it to upgrade the oil to finished products. In return for the 50 percent ownership in the refineries – Wood River, located in Illinois, and Borger, located in Texas — ConocoPhillips was granted a 50 percent stake in the Cenovus projects at Christina Lake (the site I visited) and Foster Creek.

Cenovus has been one of the most innovative companies in the heavy oil space. Technological innovations such as injecting butane along with steam and its Wedge Well™ technology, which accesses additional bitumen by adding a single horizontal well between the two SAGD wells, have driven down costs while consuming less energy and increasing resource recovery to a range of 60 to 70 percent.

In 2012, Cenovus averaged 165,000 bpd of oil and natural gas liquids, a 23 percent increase over 2011. The company’s strategic plan aims to increase net crude oil production to 500,000 bpd by the end of 2021. Natural gas production fell by 9 percent to 594 million cubic feet per day as the company focused more on liquids production. Total proved reserves of oil, natural gas, and NGLs increased 12 percent to 2.2 billion barrels.

Cenovus has a market capitalization of $21.7 billion and an enterprise value of $27.5 billion. The EV/EBITDA is 6.8. The company has a debt to equity ratio of 63.4 percent, a profit margin of 3.4 percent, and a return on equity of 6 percent. (Financial results have been dragged down this year by weak refining conditions.) The current dividend yield is 3.2 percent.

Neither Cenovus nor CNR has particularly pleased investors of late, and we’re not rushing to add either stock to a portfolio since operating margins and the growth rates trail those of the top US shale drillers we recommend. But as the cost of these Canadian barrels comes down and the shipping infrastructure improves, that may change. But it’s already clear is that Canadian oil sands will have to be reckoned with in the global market for crude and in the financial arena.