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By Robert Rapier on Dec 9, 2013 with 20 responses

The Cost of Production and Energy Return of Oil Sands


Today’s article continues the series covering my recent trip to the Athabasca oil sands around Fort McMurray, Alberta. This is an annual trip that the Canadian government hosts for energy journalists, and expenses for the trip were paid for by the Canadian government.

Previous articles in this series include:

Today I want to discuss in more detail the two companies that we visited on this trip: Canadian Natural Resources Limited (NYSE: CNQ, TSE: CNQ) and Cenovus Energy (NYSE: CVE, TSE: CVE). I will detail the cost of oil sands production via the different methods these companies utilize, as well as the energy return on energy invested (EROEI) of extracting the bitumen.

Canadian Natural Resources

One of the visits we made on the trip was to Canadian Natural Resources’ (CNRL) 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.

Horizon Aerial - plant site
Aerial view of the Horizon oil sands facility. Source: Canadian Natural Resources Ltd.

The process for producing bitumen via surface mining was covered in detail in last week’s article. To review, the process consists of:

  • Removal of the overburden (timber and 30-40 meters of peat, clay, and sand)
  • Digging up the bitumen-laden ore and transporting it to the processing facility
  • Mixing the ore with hot water to separate the bitumen from the sand
  • Transporting the remaining sand and residual bitumen to the tailings ponds for further settling
  • Upgrading the bitumen into synthetic crude oil (this is optional, but CNRL does upgrade at Horizon)
  • Ultimate reclamation of the mining site and tailings ponds

My general observations were that this is an operation of enormous magnitude. The open pits were huge, as were the trucks to transport the ore. The trucks did kick up quite a bit of dust as they drove past my group at a frequent pace. Other than the dust, there wasn’t much smell unless you stood directly downwind of the ore processing facility.

Horizon Oil Sands’ leases are north of Fort McMurray 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. CNRL estimates that 6 billion to 8 billion barrels are ultimately recoverable. Given the scale of the resource base,  CNRL expects the mine and plant facilities to produce for decades without the production declines normally associated with conventional crude oil wells.

At present, the Horizon project 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 plan to 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 are projected to 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. Considering that the going rate for SCO over the past couple of years has been $90-$100/bbl, the project should be highly profitable for the company.

While the Horizon project is a key part of CNRL’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. CNRL’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 2013 were $1.86 billion (Canadian), versus $1.54 billion for the same time period a year ago.

Besides CNRL, other companies involved in surface mining of oil sands include 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).

Cenovus Energy

Cenovus Energy was formed on Dec. 1, 2009 when Encana Corp. split into two companies: the oil company Cenovus Energy and the natural gas company Encana (NYSE: ECA, TSE: ECA). 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 was a pioneer in the Athabasca oil sands in utilizing steam assisted gravity drainage (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 that has boosted oil production in the US. This process was also explained in some detail in last week’s column, but consists of:

  • Drilling a pair of horizontal wells, one about 5 meters above the other
  • Extracting brackish ground water and converting that to steam
  • Injecting steam into the upper well for months to heat up the bitumen
  • Pumping the hot liquid bitumen from the lower well (steam injection continues during most of the well’s lifetime)
  • Separating the returned water from the bitumen and reusing the water in the process

Cenovus is different from CNRL 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 (NYSE: COP) 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 the company’s Wedge Well™ technology, which accesses additional bitumen by adding a single horizontal well between a pair of SAGD wells, have driven down costs while consuming less energy and increasing resource recovery to a range of 60 to 70 percent.


How Wedge Well™ technology works. Source: Cenovus

Cenovus reported costs that were much lower than I expected. At the Christina Lake site I visited, their cost of production — which factors in taxes plus a 9 percent return — was cited at $35-$45/bbl. This is cheaper than the overall cost to produce bitumen via surface mining at CNRL, but Cenovus’ finished product is bitumen and not the higher value synthetic crude oil that CNRL produces.

Cenovus Costs

Cenovus cost of bitumen production. Source: Cenovus Investor Presentation

However, their costs have been declining as they climbed the learning curve. Between 2010 and 2013 they reported that they had reduced costs by $5-$10/bbl. But they expect that their emerging bitumen projects at Grand Rapids and Telephone Lake will be around $20/bbl more to produce than their currently-producing projects. Because Canadian heavy oil has historically traded at a $30-$40/bbl discount to West Texas Intermediate (WTI) crude due to logistical constraints, these emerging bitumen projects may require WTI prices above $90/bbl to be economical.

According to Cenovus, there are no tax incentives available that are specific to oil sands production. I took that to mean that there may be industry-wide tax breaks, but they are the same for conventional oil production and for bitumen production.

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. The company’s total proved reserves of oil, natural gas, and NGLs increased 12 percent in 2012 to 2.2 billion barrels.

Energy Return on Energy Invested

The amount of energy required to produce bitumen has been a hot topic for many years. Some argue that these projects are a poor way to use energy, because the energy return on energy invested (EROEI) is ~ 3:1 (which would mean it takes 1 BTU of energy input to produce 3 BTUs of bitumen output).

This is a simplistic picture, and only partially correct. First, as I explained in “How Not to Use EROEI“, the EROEI of a process doesn’t necessarily say much about the economics of the process. If you are using cheap energy inputs to produce a higher value product, then a low EROEI might be perfectly acceptable from an economic point of view. In the case of SAGD, they are using cheap natural gas to produce much more valuable crude oil. Thus, in this case a low EROEI itself says nothing about the economic viability of the process.

What a low EROEI does indicate is that fossil fuel resources are being depleted at a faster rate; the lower the EROEI the faster the depletion. Thus, lower EROEI projects are generally worse from an environmental/greenhouse gas emissions point of view.

The biggest problem with the low EROEI claims is that there is great variation across the industry. To illustrate, consider that in any industry, competitive analyses are often done by 3rd parties. (I have personally been involved in such analyses). The organization doing the evaluating will be given access to data from participating companies to provide an overall analysis of particular metrics. They share the results with the participating companies, but each company is only allowed to see their rank among the other companies. In other words, in the graphic below Cenovus knows which bars belong to them, and they know which companies participated, but they don’t know which other bars belong to which companies:

Cenovus Steam to Oil RatioSteam to Oil Ratio. Source: Cenovus Investor Presentation

So we can see that in this analysis of data collected by IHS CERA, the four lowest “steam to oil ratios” – a measure of the relative indication of how much energy is being used — are found in four Cenovus projects. FC, TL, CL, and NL are Foster Creek, Telephone Lake, Christina Lake, and Narrows Lake. Their Grand Rapids (GR) project is in the middle of the pack.

But how does a “steam to oil ratio” (SOR) translate to EROEI? I spent a lot of time going back and forth with Cenovus on this issue. As an engineer, a “barrel of steam” really has no absolute meaning, as it can have differing energy content depending on the temperature and pressure of the steam. So I asked for actual BTUs of energy to produce a barrel of steam, so that I could make relative comparisons. After several follow-up email exchanges and a phone call, here is what I was told by Brett Harris, a Cenovus spokesperson:

As of the second quarter of 2012, we were using approximately 840 cubic feet of natural gas to produce 1 barrel of oil. On a BTU basis, that’s approximately 856,800 BTUs of natural gas to produce approximately 5.8 million BTUs worth of oil, which is a ratio of about 1 to 6.8.

Unfortunately, I don’t have the electricity input for 2012. The last year for which I have fully calculated numbers was 2008. In 2008, at our Christina Lake operations, electricity and diesel accounted for about 5% of the total energy input to create a barrel of oil. Natural gas accounted for the remaining 95%. At the time, our all in energy ratio to produce a barrel of oil was about 1 to 6.3. (I believe that has improved since then, but I don’t have the electricity numbers to calculate a more recent all in number for you).

So if I use the 2012 ratio of 840 cubic feet of natural gas to produce a barrel of oil, add another 5% to account for diesel and gasoline, I arrive at about 900,000 BTUs of energy to produce 5.8 million BTUs of oil. That results in an EROEI for Cenovus’ bitumen production of 6.4 to 1. The EROEI has been improving over time as they have learned what works well and what doesn’t, and it is approaching the lower range of conventional oil production.

But note in the graphic that while the SOR for most Cenovus projects is down in the 2 to 1 ratio (2.1 according to the graphic below), one of their peers uses a lot more energy at ~7.8 to 1 for the SOR. While the comparison isn’t perfect, because some companies may define a “barrel of steam” in slightly different ways, we can make a rough estimate of the EROEI for the industry laggards.

If we assume that 900,000 BTUs of energy inputs are approximately the equivalent of a 2.1 to 1 SOR, then a 7.8 SOR would be approximately 3.3 million BTUs of inputs to produce 5.8 million BTUs of oil. (That may be a slight overestimate as that also assumes that the laggards are less efficient with electricity and diesel; if we assume that their electricity and diesel efficiency is the same as that of Cenovus, I come up with 3.2 million BTUs of input).

That means for the worst in class, the EROEI is only about 1.8 to 1 (5.8 million output for 3.3 million input). If these were fungible inputs and outputs — for example, if they had to cannibalize some of their oil to produce the energy for the process — this wouldn’t be economically viable for that particular project. Perhaps their process is still economical with cheap natural gas inputs and oil outputs, but the very existence of this process means that those low-ball EROEIs regarding oil sands production have some truth to them.

While the one company with an SOR of ~7.8 is a clear outlier, there are a number of companies operating in the 4 to 5 range for SOR. Assuming an average of 4.5 for the SOR and repeating the earlier exercise, I arrive at an EROEI for these companies of 3 to 1. So it would appear that the vast majority of oil sands operators are operating down in the 3 to 1 range, with the very important caveat that it is possible to have an EROEI of double that — as Cenovus has demonstrated.

How does this compare to surface mining? According to the following graphic, Cenovus’ SAGD process is better than the average surface mining process, which itself looks to have an SOR of about 3 to 1. That would make the EROEI of surface mining of bitumen about 4.3 to 1 — itself better than the average in situ process.

GHG Intensity across various crudes

GHG Intensity Across Comparable Crudes. Source: Cenovus Investor Presentation

One other item of interest from that graphic is that it indicates that Cenovus’ bitumen production actually has a better energy return from well-to-tank than Nigerian light oil or California heavy oil. This would take into account the production, transport, and refining of the oil. Saudi Arabian medium crude has the lowest energy inputs on the graphic, indicating it has the highest EROEI. (Note that in the previous EROEI calculations, the refining step isn’t included; refining to finished products requires another 500,000 to 600,000 BTUs of energy input per barrel of finished product).

In next week’s article I will conclude the series on the Athabasca oil sands by examining the logistical issues of getting the oil sands to market, including the impact of the Keystone XL decision (regardless of which way it goes).

Link to Original Article: The Cost of Production and Energy Return of Oil Sands

By Robert Rapier. You can find me on TwitterLinkedIn, or Facebook.

  1. By Eric on December 9, 2013 at 5:35 pm

    Thank you Robert! That’s one of the single most informative pieces I’ve read on the oil sands.

  2. By Tom G. on December 10, 2013 at 2:15 pm

    Excellent posting Robert.

    One thing I normally look for when visiting an industrial facility is how well they manage their maintenance program. You can tell alot about a company by just observing the condition of their pumps, valves, storage tanks, berms, pipelines and electrical systems.

    During your wall-abouts, what did you observe? Did the facilities look well maintained or did it look like there were many opportunities for potential problems?

    • By Robert Rapier on December 16, 2013 at 8:02 pm

      I had meant to address this earlier and forgot. These facilities are all new, so certainly I didn’t notice any maintenance issues. I am always conscious of smells coming from a process, but I didn’t smell anything at Cenovus and only smelled anything at CNRL when I was downwind of where they were putting the ore into the separation drums.

  3. By Joe Clarkson on December 10, 2013 at 7:40 pm

    Your oils sands series has been very informative. Thank you.

    But I don’t understand your statement that “Production costs at Horizon are largely fixed, so production costs on a per barrel basis are projected to decline significantly when Phases 2 and 3 come on-stream.” I would think that overall production costs would be pretty proportional to production unless they invested in far more capital than they needed for current production. To get more sand out of the ground they will need more trucks, operators, roads etc. Please explain how their production costs are “fixed”.

    • By Robert Rapier on December 10, 2013 at 8:41 pm

      That was a direct quote from them, but I think it’s because the entire Horizon facility is sized for Phases 2 and 3. And that’s where the majority of the production costs reside. True, they will require more trucks, etc., which will increase their costs somewhat, but as a result of the capital already invested in Horizon they see these expansions driving down their overall costs.

  4. By George on December 11, 2013 at 12:09 am

    A barrel of WTI Oil has 5.8 Million BTU per Barrel. A barrel of Bitumen is more like 6.2 Million BTU depending on its density.

    • By Robert Rapier on December 11, 2013 at 12:16 am

      I have always used 5.8 million BTUs for WTI, but Cenovus gave me that same number for bitumen. I would not be surprised that the energy density would be a bit higher, but I am just using the number they provided for that.

  5. By Forrest on December 11, 2013 at 9:01 am

    A side bar- The 3:1 EROEI average, energy invested calculates to 1.9 mbtu per 5.8 mbtu barrel of oil. Add the .6 mbtu for refining drops the ratio to 2.3:1. So the USDA calculates ethanol EROEI of 2.34:1. The earlier lower ethanol ratio’s didn’t appropriate correctly for co-products. Also, I think the future of increasing these ratio’s is definitely in the bio-fuels side. Petrol industry had the privilege of decades to polish efficiency, production, technology, infrastructure, and maximize combustion efficiency. Bio fuels just a few years old, even so, bio-fuels have undergone much improvements to date and exciting R&D pathways for better future. Bio-fuel as compared has unlimited pathways to improve. I do like the increase oil production and petro’s new found resources per technological advances, just saying we shouldn’t drop the ball with the bio-fuel resource. We did that once before, not a good thing to do.

    • By Optimist on December 12, 2013 at 3:23 pm

      Spoken like a true Ethanol Industry spokesman. The co-products are irrelevant, because the demand for them are already being exceeded. DDGS is being exported. Ramp up ethanol production more and you’d be sending the co-products to the landfill.

      We’ll see what the future holds. The challenge for biofuels will be scale. assuming there is a biofuel industry that doesn’t hog our food supply…

      • By Forrest on December 13, 2013 at 10:17 am

        I have no connections, but like the fuel. The ddg feed a valuable feedstock. Interesting that cattle or ruminates not designed for corn, but grass. They do better on grass and have healthy nutritional profile if eating the stuff. Farmers tell me the meat isn’t as tasty as corn fed, though. Brewing ethanol with the typical microbes consumes the starch part of corn kernal, which is the part not contributing to health profile of meat. The protein and valuable nutritional components are left intact for animal feed, but most forget the microbes. The microbes contribute immensely to feed value. Nowadays we learn of value of fermented foods, the Japanese utilize this type of food and enjoy better health for the consumption. Yes, they pay a premium for the ddg’s, thank you. Also, they learned corn oil not that good upon feed and most plants currently implemented new technology to take it out. Another revenue stream for these plants and some are processing biodiesel as result. Biodiesel production jumped per this technology. Also, per above energy in/out calculations of ethanol. These plants could do a lot better upon these calculation if introducing cogen with hot air turbine. Basically, anywhere you need natural gas thermal power of good quantity you should setup cogen to first produce electric power with those efficient hot air turbines. Very little temperature lost in doing so, meaning not much bearing on the distillation process of ethanol (no more fuel required).

  6. By Russ Finley on December 11, 2013 at 11:16 pm

    Nice graphics. GHG emissions don’t appear to be any worse than the California heavy oil.

  7. By Dominic Doucet on December 16, 2013 at 10:28 am


    Interesting read.

    About Canadian Natural Resources’ (CNRL), you are saying: “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. ”

    This is surprising. Do you think the production cost for CNRL is at the same level than the production cost of others oil sands projects in Canada?

    thank you


    • By Robert Rapier on December 16, 2013 at 10:40 am

      I would imagine that they are all in a similar range. The in situ folks probably have a pretty wide range as they had a wide range of energy inputs for the process. The highest cost producers are probably $20/bbl higher than the lowest cost producers.

      Were you thinking CNRL’s costs would be higher? Remember that they were putting in these projects in 2005 when oil was $40-$50/bbl. So they had to have a fairly good idea that they would make money down in that range.

      • By Dominic Doucet on December 16, 2013 at 10:54 am

        Thank you.

        I was misinformed. I thought the cost of production would be more around $70/bbl -$90/bbl. Working as an energy analyst in Québec, my clients rarely need informations on the oil sands industries, so my sources are not up-to-date or reliable.

        I’m waiting for your next article about logistical issues of oil sands, next year the Energy East Pipeline Project will surely be a political issues in Québec and other eastern canadian provinces.


        • By Robert Rapier on December 16, 2013 at 11:06 am

          It’s probably the case that the marginal cost is indeed in that range. My own information has been that the marginal cost for oil sands production is >$70/bbl.

  8. By Zohre on December 2, 2014 at 4:28 pm

    I need information about conversion process of Bitumen to it possible?
    I’m interested in processing of bitumen.

    • By Tom G. on December 2, 2014 at 5:18 pm

      You might want to contact Robert Rapier on Facebook. I am not sure how frequently he looks at very old blog postings.

  9. By thoughtrational on March 29, 2015 at 4:08 pm

    How do you square these numbers provided by IEA’s ETSAP in 2010 with the numbers you received from your source? Do their numbers include the GHG emissions from the topsoil stripping and transport?


    Direct quote from top of page five

    “the production of synthetic crude from oil sand are
    between 10.2 and 26.9 gCO2/MJ (62 and 164
    kgCO2/bbl) for surface mining and upgrading, and
    between 16.2 and 28.9 gCO2/MJ (99 and 176
    kgCO2/bbl) for in-situ techniques and upgrading. For
    comparison, the emissions from conventional oil
    production are between 4.4 and 4.7 gCO2/MJ (27 and
    58 kgCO2/bbl). According to the study by APO
    Netherlands the CO2 emissions from oil shale
    production are as high as 232% to 892% of the
    emissions resulting from conventional production [23].”

    Thanks in advance for your reply.

    • By Robert Rapier on March 29, 2015 at 10:36 pm

      One is that they were using pretty outdated numbers. They did say that the energy efficiency improved by a lot as they climbed up the learning curve — which is understandable. The second is that I don’t know if they consider GHG emissions from removing the overburden. So that could be a difference in the ETSAP report was assigning high GHG values to this.

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