Oil sand is consolidated sandstone saturated with a dense and extremely viscous form of hydrocarbons that is called bitumen or (colloquially) tar. Bitumen deposits are found in a number of countries, but the only economically relevant production happens in the Canadian province of Alberta. The most prominent deposits there are the Athabasca oil sands. Although oil sand deposits in the Venezuelan Orinoco Belt are even more promising, due to the political instability in that country little endeavor has been made to produce them.
Oil sands are either produced via surface mining or sub-surface in-situ production (either steam-assisted gravity drainage - SAGD or cyclic steam stimulation - CSS). Bitumen that is produced from surface mining is sometimes upgraded on-site and delivered as synthetic crude oil - SCO, which has the advantage of higher prices and enables transport through conventional pipelines, but also causes high costs. CSS means the injection of steam from a wellbore into the reservoir. After some time, where the steam is left to soak, the same well is turned into production mode. SAGD is an enhanced oil recovery technology used for production of heavy crude oil and bitumen. It primarily consists of two horizontal wells that are positioned only a few meters away from each other. Steam is injected into the upper wellbore in order to heat the oil and reduce its viscosity (the fluid's resistance to flow). Subsequently, the lower wellbore pumps the oil out. 2012 was the first year, with in-situ production exceeding production from mining.
In a world, where oil production from traditional sources has most likely reached a plateau, the economic importance of oil sands has risen. In this article and the subsequent one I investigate production costs of oil companies that are primarily engaged in the hydrocarbon extraction from oil sands. This article features Cenovus (NYSE:CVE), Canadian Natural Resources (NYSE:CNQ) and Canadian Oil Sands (OTCQX:COSWF). I have also calculated 2013's production costs for 121 companies. The link to the summary can be find here. It also contains links to articles that discuss the investigated companies in more details.
The key point for me is to catch the real production costs of hydrocarbons as accurate as possible. For that reason I only consider costs that are directly related to oil and gas production. As the upstream business is a pure commodity business, many companies have bought derivatives to hedge their sales. As gains or losses from that instruments are not directly related to production, I do not consider them directly in my method. Nevertheless, as they might have impact on the future of the company, I mention them if they are significantly high. The same is true for impairments.
In contrast to my other articles, where I investigate operations that produce oil and gas simultaneously, only bitumen and SCO are produced from oil sands. It makes sense to use barrel rather than boe, as I did in my previous articles.
Commonly, costs are divided in costs that can directly be related to production (cost of sales) and costs that cannot directly be related to output (overhead). However, many oil companies are also active in downstream and midstream or other economic sectors (e.g. ExxonMobil (NYSE:XOM) in chemical engineering). Hence, I have divided sales, general and administration expenses (SG&A) by total revenues and multiplied it with the revenue of the E&P division to get SG&A for E&P. I did the same for any similar type of cost (marketing expenses, R&D) and for financial expenses. Depreciation, Depletion and amortization, on the other hand, can be directly linked to oil production.
Costs of sales are divided into 3 sub-categories:
- Exploration costs
- Lifting costs
- Non-income related taxes
Exploration costs are costs related to all attempts to find hydrocarbons. This category includes cost for geological surveys and scientific studies as well as drilling costs. As the occurrence of oil sands is generally well known, this cost category has only a tiny contribution to total costs.
Lifting costs are the costs associated with the operation of oil and gas wells to bring hydrocarbons to the surface after wells (facilities necessary for the production of oil) have been drilled. This figure includes labor costs, electricity costs and maintenance costs.
Non-income related taxes: as production of hydrocarbons is such a lucrative business, governments also want to have their shares. There exists an abundance of different model how the state can profit from hydrocarbon production (profit sharing, royalties, etc.).
It might be, that different companies use different categories for the same type of expenses, but eventually the sum of all costs should be their total cost for producing 1 bbl.
The following figure shows the pattern of the cost model:
As I have noticed in one of my articles, that cash flow situation does not look well for the majors. In the long term, a profitable company must be able to generate enough cash flow to cover its capex and to buy money back to its shareholders (either via dividends or share buybacks). Therefore I included operating cash flow and total capex in my data. Operating cash flow and capital expenditure both refer to the whole company. Capital expenditure is investment in assets as well as in subsidiaries if they are not consolidated. This number does not include any subtractions because of the selling of assets. I also add the cash flow companies generated through sale of assets.
Application on 3 Oil Sand Producers
I have applied my method to 3 major North American oil sand producers. If the company also produces conventional oil, I only considered the oil sand division. Last year I have already considered all 3 companies, so I am now able to compare numbers. However, this year I make a small change in the types of costs I consider: some oil sand producer blend their bitumen with other oils they purchase and book sales from the total blend as revenue. In this article I only consider revenues from own production. Therefore, I excluded costs for blending oil from my model. As mentioned above, oil sand producer are mainly Canadian companies. Therefore, I had to convert CAD in USD. I used an exchange rate of 0.905.
The results for 2014 can be found in the table below:
(source: Annual Report 2014 if already published, otherwise company websites)
I have also used my methodology in the following articles:
- 2013's Costs for 121 Companies
- Independents I
- Independents II
- Independents III
- Shale Oil Producers I
- Shale Gas Producer
All of the three companies could increase their production from 2013 to 2014. However, 2015 and future year might see falling production from oil sands as capex is cut as a reaction to the decrease in oil price. It is also very easy to see, which companies sell bitumen (Cenovus) and which upgrade and sell SCO (CNR and CNS).
As I included last year sales of blended oil for Cenovus, it is quite difficult to directly compare results. Nevertheless, the pre-income tax margin remained relatively stable for the company. Cenovus obviously reduced its debts, as interest expenses per bbl fell by nearly $1. In Q4 the company could only realize $44.5 per bbl bitumen and got a netback (revenue minus exploration, lifting and non-income tax costs) of $27.56 per bbl bitumen. This might be an outlook for 2015 and can explain why oil sand companies delay or even cancel their projects at today's price level.
CNR got slightly less revenue per bbl in 2014 than it got in 2013. On the other hand, the company could decrease its costs. It did so across all cost categories with non-income related taxes being the only exception. Especially notable is the 25% decrease in SG&A expenses. Pre-income tax margin rose from 29% to 34%. However, CNR was only able to fund 73.5% of its capital expenditure with cash flow generated from operations.
COS raised its production slightly from 2013 to 2014. The enterprise shows a pattern similar to CNR. Revenues per bbl went down a bit, but the company was able to decrease costs much more (in terms of percentage). The biggest decrease in costs was realized in lifting costs, while non-income related taxes rose. Just like the other two companies, COS reduced its SG&A expenses per bbl significantly. As a result pre-income tax margin increased from 16% in 2013 to 20% in 2014.
The data investigated so far show a common pattern: oil sand producer streamlined their operational costs throughout 2014. However, they were also affected by the decline in the oil price, a factor they can hardly control. In 2014, that saw three quarters with relatively high oil prices, the upstream companies could offset the decrease in revenue with cost savings. If this will also be possible in 2015, is highly questionable. Oil sands are unconventional resources and are therefore much more complicated (and more expansive) to produce than conventional resources. Margins will most likely remain below margins of conventional oil producers.
The dire cash flow pattern I observed in all my articles so far, is also valid for the oil sand producers, further proof, that today's oil price level is not sustainable.
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