Tuesday, October 2, 2007

An Overview of the Canadian Oil Sands Industry

Canadian oil sands are a type of heavy oil resource, mixed with sand and water which forms a substance which resembles an "oily mush." The bitumen from the oil sands -- chemically long hydrocarbon chains that are close in structure to those of asphalt -- can be upgraded, after separation from the sand and water, to syncrude (a type of heavy oil), which then can be further refined to gasoline, jet oil, and other premium petroleum products. The majority of Canadian oil sands are located in the Athabasca region of Alberta, an area covering approximately 30,000 square miles, but significant oil sands deposits are also found in the "Peace River" and "Cold Lake" deposits, which are are also located in Northern Alberta but in distinct regions from Athabasca.

Note also, there are large oil sand deposits in Venezuela and Russia, but this analysis only covers the Canadian oil sands.

Oil Sands Majors:

Canadian oil sands production is up and running currently (in contrast with Venezuelan and Russian oil sand deposits, which are also very large but are not developed), with the majority of the production coming from four firms: (termed "Oil Sand Majors" here):

1. Syncrude -- a consortium of oil majors and the managing Canadian partner Canadian Oil Sands, Inc, which produces approximately 361,000 barrels of syncrude a day (at 6/07) mainly through mining methods

2. Suncor -- the oldest Canadian firm, 100%, publicly held, which produces approximately 270,000 barrels of syncrude at day at 6/07, produced mainly through mining methods.

3. Imperial Oil -- approximately 70% owned by ExxonMobile, which produces 140,000 barrels per day produced in the "Cold Lake" region above (not the Athabasca region above) through in-situ methods, and, in addition, owns 25% of Syncrude.

4. Athabasca Oil Sands Project -- 20% owned by the public Western Oil Sands (ticker WTO), 60% owned by Shell, and 20% owned by Chevron, which produces 180 bpd in mid 2007 produced mainly through mining methods

Note that other firms are up and running, including Encana, Nexen and the Consortiums Western Oil Sands Inc, North American Oil Sands Corporation -- producing firms minority and majority owned by partners Chevron, Statoil and Shell and other oil majors. However, these firms currently (9/07) produce on a significantly lower scale than the four "Oil Sand Majors" listed above, although plan to increase production going forward -- production forecasts are discussed below. Further, note that only three firms, Syncrude, Suncor and the Athabasca Oil Sands Project, are producing oil sands through mining methods (to be described more fully below) on a major scale, while other firms are producing oil sands currently through "in-situ" methods, which involves two methods of pumping hot steam underground and collecting the melted bitumen.

Oil Sands Firms Overview:

The following discloses the major oil sands producers currently and in future years, with the following data.

Data Included: firm name; ticker; total leased oil sands area (square miles); recoverable resources (of syncrude); Oil Sands Current Production; Enterprise Value, P/E ratio TTM/Projected (note -- p/e ratios may include conventional oil production earnings in addition to oil sands earnings)

Data from SEC filings and presentations from the Investing in Alberta's Oil Sand's Conference June 2006: http://www.oilsandsconference.com/program.htm

Syncrude; (investors can purchase indirectly through Canadian oil Sands Trust, 37% owner, COSWF); 386 square miles; 10 billion barrels; 361,000 bpd, 500,000 bpd by 2015 projected; $US43Bn; p/e: 18x (p/e of 37% owner Canadian Oil Sands Trust, inc)/proj p/e: na

Suncor; SU; 772 square miles; 13 billion barrels; 270,00 bpd current, 500 to 550K bpd by 2012; $US45Bn; 19.2x ttm/14.6x proj (oil sands only)

Athabasca Oil Sands Project; 20% owned by Western Oil Sands; WTOIF; 55 square miles; 8.9 billion barrels; 35 kbpd, mainly through mining; projected 500K total bpd produced by 2015; $US30 Billion; 28x/ na

Imperial Oil (25% owner of Syncrude and indep. producer); IMO; 727 square miles (w/Syncrude); 10 billion barrels (3 billion mining, 7 billion in situ)(w/ Syncrude); 140,000 bpd ex Syncrude at Cold Lake 4% growth forecasted, 300K bpd at Kearn by 2020; $US45Bn; 14.8x/16.0x

Canadian Natural Resources; CNQ; 177 square miles; 6 billion barrels; 110K bpd 2008, 232K bpd 2011; (in situ); $US52.13Bn; 15.9x; 17.8x

PetroCanada (12% interest in Syncrude, plus substantial indep projects); PCZ; 9.8 square miles; 10 billion barrels estimated ex Syncrude; 27,000 bpd ex Syncrude current, 320,000 bpd independent projected by 2015; $US29.5Bn; 11.6x ttm/9.90x proj

Encana (mainly natural gas producer but moving into in situ oil sands production); ECA; 77 square miles; resources na; 48 kbpd current oil sands production; future oil sands production na; $US57.7Bn; 12.6x ttm/13.8x proj

Nexen (mainly conventional oil and gas producer but owns 7.23% of Syncrude & small indep oil sands operation); NXY; 7.7 square miles ex Syncrude; 27,000 bpd pro-rata Syncrude, 100,000 bpd independent by 2017; $US15.7Bn; 37x ttm, na

Statoil (national oil co of Norway, bought 100% of North American Sands Corporation in 2006 for $US2Bn); STO; 8.9 square miles; 0 current, 170,000 bpd by 2015; $US82Bn; 9.8x ttm/11.6x proj

Note that the list above is not exhaustive as certain smaller producers have not been included, such as Synenco, Devon Energy, Connacho Oil and Gas, Husky Energy, and CanWest.

What is the difference between Oil Sands Mining and Oil Sands "In Situ" Production?

The majority of oil sands production currently (at mid to late 2007) comes from mining methods, which essentially can be described as follows: huge digging machines, which dig surface oil sand, load this oil sand into huge trucks, and move the oil sand to processing facilities. It is emphasized that these trucks and digging machines and shovels are huge, as the Caterpillar 797 truck used for hauling oil sands has been compared by its manufacturer in size to an entire Wal-Mart store and can crush an SUV underneath and the driver of the 797 will not feel a bump. Mining projects account for over 60% of total oil production and a higher majority of production for Syncrude and Suncor's current oil sand production.

In Situ production is described as the melting of underground oil sands and collection of the resultant melted bitumen by vents. In situ production is utilized when the oil sand resource is located far underground, so that surface mining is not possible -- note, that by area, over 75% of Alberta's oil sands are deep underground and appropriate only for in situ production. According to Imperial Oil, which claims to be the most experienced in-situ producer currently at in situ production of 170,000 barrels per day, there are certain geological requirements for in situ production with current technologies: that is, 1. the reservoir should be "clean" with a high bitumen saturation, and/or 2. the reservoir should have a capping shale cover (to keep the heat contained). It is not known what percentage of underground oil sands in Alberta possess these requirements.

Volumes from "In Situ" Extraction is Most Likely Less Predictable Going Forward than Volumes from Mining Extraction:

There is some uncertainty going forward in the predictability of future volumes from in situ production. Bitumen produced by in situ production from a single location has not resulted (as of late 2007) in more than 170,000 barrels per day -- as is the current production level at Imperial Oil's current Cold Lake operations (although note that Imperial Oil is confident that they can continue to increase the production from this property by 4% per annum going forward). Further, conceptually, it is more straightforward to increase production to increase by mining methods -- that is, it is simple under mining methods to increase the number of shovels and trucks, and upgrading and refining capacity. In contrast, with in situ production, it is unclear (in the author's opinion only) whether heating the underground reservoir at a higher temperature to increase bitumen flow and/or more vents constructed to collect melted bitumen would increase production at a steady rate.

Note also that only a relatively small area of the total Canadian oil sands area -- less than 25% of the geographic area -- can be produced with surface mining methods, as surface mining only is applicable when the oil sands are located near the surface, defined as under less than 75 meters of overburden. The mineable area of the oil sands is already nearly 100% leased according to maps from Alberta Energy: http://www.energy.gov.ab.ca/LandAccess/pdfs/OilSands_Projects.pdf (large pdf warning).

Therefore, in the author's view, the companies with large lease areas and operations in the mineable areas of the Athabasca oil sands territory (Suncor, Syncrude and Athabasca Oil Sands Project) have increased predictability of future resource development, and therefore should (all other factors equal) be valued at premiums to reserves verses in situ-heavy producers.

Is There a Difference in Terms of Profitability between Mining and In Situ Production Methods of Oil Sands?

According to Nexen Inc, overall economics are similar between in situ and mining methods -- with a slight edge to the mining process, estimating an operating margin of 56% for mining methods vs 50% for in situ processes per barrel of oil based on $50 oil. However, costs in individual processes can range widely, from $18 to $30 (at late 07) per barrel of heavy oil, depending on the location and geology of the resource. But, according to Nexen, there are significant differences in components of cost between the two methods: natural gas usage in in situ production is generally more than twice the level than in mining production -- because natural gas is used to heat the bitumen underground. But other production costs are more than three times the level in mining methods verses in situ -- because the mining equipment and trucks are expensive to operate, and the sand component of the oil sand from mining methods must be separated out in an extraction process. Upgrading and refining costs are similar between the two methods. See: the Nexen Presentation on this page for details: http://www.oilsandsconference.com/program.htm

The upshot of the above discussion is that both methods in theory can provide a verystrong return to shareholders, and therefore the main difference (in the author's opinion) between the two methods is the attainability of production levels between the two methods -- that is, the mining method is comparatively more reliable and therefore projected increased numbers can be relied upon more securely, as stated in the section above.

How Profitable are Oil Sands Firms?

Oil sands production is very profitable currently, due to the relatively high (compared to historical) price of oil. According to Morgan Stanley (link: see the Lloyd Byrne Morgan Stanley presentation on the bottom right hand concern at the Canada Institute here: http://www.wilsoncenter.org/index.cfm?topic_id=1420&fuse
action=topics.event_summary&event_id=145364)
oil sands as of 2004 returned an average of 18.0% on capital employed (ROCE of 18%) verses 15.0% for conventional North American oil production. Further, the cost per barrel of oil -- cost defined as cash costs for operation, SG&A, accretion expense, taxes other than income taxes, and DD&A) were $14 per barrel for Suncor's Millennium project verses $16 per barrel for conventional North American oil and gas production. That is to say, at 2004, according to Morgan Stanley, oil sands were actually more profitable per barrel than conventional oil production -- clearly Wall Street and most investors do not appreciate this view, given the relatively low p/e's of the oil sands majors compared to the planned growth rates.

The reasons Morgan Stanley gives for the very competitive costs of oil sands production are: a high degree of "repeatability" -- meaning steady future production and predictable inputs to achieve future production -- due to very large and relatively homogeneous reservoirs, and very low exploration costs, verses conventional oil and gas.

The results of the two, pure play major oil sand producers (Suncor and Syncrude) underscore the profitability of oil sands production demonstrated by the following (source company financial press releases):

Firm; 6 Months 07 Revenue Growth; 6 Mo 07 Net Income Growth (Y/Y); 6 Mo Net Income Margin (%)
Suncor; 4.8% rev growth; -38% net profit growth (due to one time items); 14.3% net profit margin (24.4% net margin in the year earlier period)
Syncrude; 29.2% rev growth; 25.9% net profit growth (before one time items); 19.3% net margin

Will Escalating Costs of Labor, and Equipment Cause Oil Sands Production to Become Unprofitable in Future Years?

A comprehensive analysis of future costs is not presented here, although there has been significant press coverage of rising oil sands labor and equipment costs. However, as shown above, the Oil Sand Majors are still very profitable as the rising price of oil more than offsets the rising operational costs. But in the future, if operational costs go up without a corresponding rise in the price of oil, then this will certainly hurt oil sands firms' profitability.

Will environmental concerns over water usage, environmental degradation and/or CO2 production derail future increased oil sands production?

It is assessment of this analysis that not likely that environmental concerns, particularly concerning water, will derail oil sands growth going forward, as the actual water usage is not extremely large -- only 1% currently of the Athabasca River, which is significantly lower than farming usage. http://calsun.canoe.ca/News/Alberta/2006/11/13/2339858.html Oil Sands extraction uses between 2-4 barrels of water per barrel of oil, and this water can be recycled -- further, the amount of water flowing through a moderately sized (or even small) river is huge compared to normal amounts of oil produced in normal oil sands operations. Even with oil sands production increasing three fold, the water usage is only expected to increase to 3% of the Athabasca River.

The amount of Co2 production is more difficult to estimate, and the largest oil sands producers are now among the largest Co2 producers in Canada. Concerning environmental degrigation, oil sands producers have assured to remediate oil sands mined areas: http://www.suncor.com/default.aspx?ID=2

Source of Value for Oil Sands Firms: Size and Quality of Leased Land

According to Alberta Energy, the total area of the Athabasca oil sands that have been leased for purposes of oil sands extraction has increased dramatically from 31% of the total area to at 6/06 to 61% at 4/07 (and is likely to have increased further as of the time of this writing at 10/07). (according to documents at http://www.energy.gov.ab.ca/OilSands/583.asp) Further, the area of the Athabasca oil sands that can be profitably mined by surface mining has been nearly 100% leased by major oil sands firms. According to Alberta Energy, the leases range in tenure from 15 to 21 years, and can be renewed 1 year before the expiry date -- the legal language gives priority to the existing leaseholders: "Leases are continued if the required minimum level of evaluation has been attained." Evaluation is mainly seismic and other geological evaluation which would normally be done by producing firms (see section 3-7 of Alberta Energy's Alberta Oil Sands Tenure Guidelines http://www.energy.gov.ab.ca/OilSands/pdfs/GDE_ost_chp3.pdf)

The result is that the leases have a "first come, first serve" quality -- they go to the highest bidder at auction, then are able to be withheld (in effect) over the long term by the winning bidder. As such, firms with the most leases and the most geologically valuable leases have a significant advantage over firms that are late to the game and/or do not have significant land holdings -- that is, the largest firms, Suncor, Syncrude, Imperial Oil and the Athabasca Oil Sands Project process significant value due to their large lease holdings.

Conclusion:

The purpose of this analysis was to provide an overview of the producing firms in the Athabasca Oil Sands region, and provide an overview of expected profitability for investors interested in investing in Canadian oil sands. The conclusions of this analysis was that oil sands are currently profitable, and are likely to continue to be profitable -- as long as oil prices continue to stay at elevated levels. Priority was given to the more established firms in the Athabasca region, due to the fact that they have large lease holdings of land, and establish operations -- operations built when prices of equipment were are significantly lower levels than current due to the rise in steel and material costs over the last 3-4 years. Future increases in synthetic oil production is considered likely, although the exact timing of such increases by the firms is difficult to ascertain, but more reliability is given to firms which extract oil sands through mining methods.

Future posts will evaluate the impact of natural gas prices on oil sands production (note, in summary natural gas pricing is not expected to be a significant deterrent to future increased oil sands production), the differences in profitability between firms in the region, and more specifically evaluate the smaller players in the oil sands regions.

3 comments:

Ilana Reichman said...

Hi Randy, I will appreciate your help. What is your forcast for OptiCanada (OPC) for the long run? Thanks Ilana

Randy Kirk said...

Thanks for the comment -- I haven't looked into detail on OPC -- but briefly, questions for further research in what I think is a good direction: (I may do time permitting, and if the co checks out, will post answers to these)

1. I noted they are hoping to start up in situ production in mid-2008. The most important question that first pops into mind is: is the area relatively easily produceable -- for in-situ production, what that means there is sufficient capping shale and a relatively thick seam of bitumen, among other geological requirements. In situ oil sands production is still a relatively young industry so all the nitty-gritty details have not been worked out by firms -- so getting more geological data would help predict how quickly and at what cost OPC's area could be produced.

2. Also double check the figure (I have seen for OPC) that they have 4 billion barrels -- recoverable or total (usually recoverable is a fraction of total). Also if the co has partners, calculate the value based on OPC's stake, not on the total production.

3. Others questions -- it's possible they could have refining issues as it appears they will not directly own a refinery (heavy oil refineries are scarce in Alberta currently - without contractual access they will receive a lower price for their raw bitumen verses more refined products. Also there could be issues with access to pipelines.

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