Breaking Even in a Low Oil Price Environment

With the price of oil hitting levels not seen for more than four years, it's becoming an increasingly important issue for investors who are long on oil company shares, particularly given that some of the resource plays currently in vogue require prices that are far higher than conventional plays to provide a positive return on investment.  As you will see in this posting, this is particularly true for Canada's oil sands operators and companies operating in the American shale oil region.  In this posting, I will look at three different analyses that, in combination, give us some sense of the headwinds facing the oil industry.

Back in mid-2014, Reuters and Natixis published a brief article on the break-even price of producing an additional barrel of oil by geographic region, including both ethanol and biodiesel.  Here is a summary of their analysis:

The marginal cost of producing an additional barrel of oil from the Canadian oil sands is between $89 and $96 per barrel compared to $70 to $77 per barrel for U.S.-based shale oil.

Here is another analysis by the Carbon Tracker Initiative showing the break-even price for the top twenty largest oil projects in the world that require oil prices of more than $95 per barrel:

Note that the six projects that require the highest break-even oil price are all Canadian oil sands projects, both mining and in-situ.  At this point in time, one has to wonder if these high-cost options will be shelved until the price of oil retraces its decline.

From the same report by Carbon Tracker, we find these interesting graphics which show the proportions of high cost potential production for seven major oil companies:

In the worst case situation, Conoco Phillips has a portfolio containing potential projects that require an oil price of at least $75 per barrel and 36 percent require a price of at least $95 per barrel.  In the case of Shell which has the largest potential production portfolio, 45 percent of their potential projects require a market price of $75 per barrel and 30 percent require at least $95 per barrel.

Let's now look at a graph from a monthly commodity report from Scotiabank back in February 2014 which shows the full cycle break-even costs (including a 9 percent after tax return on investment) for selected production regions in North America:

The graph shows us that the weighted average of all breakeven costs for all projects is between $67 and $68 per barrel.  Among the fifty projects examined, Saskatchewan's Bakken resource play has the lowest break-even costs at $44.30 per barrel.  On the other hand, you'll note that the costs for new oil sands mining and upgrading projects is $100 per barrel, well above the break-even costs for existing oil sands production which comes in at between $60 and $65 per barrel.  SAGD (steam-assisted gravity drainage) projects are quite competitive with a break-even cost of $63.50 per barrel.  This accounts for 1.08 million barrels per day of Canada's oil production or 46 percent of Alberta's oil sands output.  It is interesting to see that the break-even costs of the U.S. Baked and Permian Basin shale oil production is quite high by comparison to the oil sands, coming in at $65 to $73 per barrel and $73 to $89 per barrel respectively.

Fortunately, many oil companies use a system of options which insure their production against price volatility.  Unfortunately, all of these come at a cost and as natural gas producers found out, they only shield production for a finite period of time.  As well, in the past, some companies have found themselves on the losing end of the bet when prices unexpectedly changed, leaving them having to declare very significant mark-to-market losses on their positions.

In closing, here is an interesting graph from Natixis showing U.S. oil production, consumption and imports since 2002:

Given the very steep production declines on shale oil producers, unless oil companies are willing to continue to stay on the production treadmill by drilling oil shale resource plays at the current lower price level that we're experiencing, we could quickly find that the purple production line falls back to its pre-2011 level, putting upward pressure on the price of oil once again....unless, of course, there is another recession!

Oil Sands and the Post-Apocalyptic Wonderland

Updated April 2019

Many of my readers will have heard of the Alberta oil sands but are not familiar with this massive reserve that is located in the northeastern corner of Alberta, Canada's petro-province.  As a suggestion, if you are not particularly interested in the background information that I am providing in this posting and want to get right to the video showing the ecological impact of the mining operations, that section of this posting starts near the bottom. 

Let's open with a map from the Alberta Government's Oil Sands Information Portal showing the extent of the oil sands, the current mineable area, the current projects and operating boundaries (in blue) for both in situ and mining operations and the location of upgraders:

Notice that Fort McMurray is in the lower centre of the map and the scale is 0.75 inches equals 10 miles. 

Here is a screen capture from Google Earth showing the extent of the current main oil sands projects:

For scale, the highway between Fort MccMurray and the southernmost oil sands mines is a four lane highway.

Before we look at the ecological impact of oil sands mining, I want to provide you with some background regarding the mines that are currently operating, their current and historical production data and plans for future expansion.  

In this screen capture from Google Earth, I have focussed on the mining projects in the southern part of the currently mined area; Syncrude's Mildred Lake and Suncor's Millennium and North Steepbank Mines, the oldest mines in the area:

In 2018, Syncrude's production capacity was 440,000 BOPD with cumulative lifetime production of over 2.8 billion barrels of oil.  Suncor's oil sands mining capabilities are located at Voyager South, Fort Hills and Joslyn.  In addition, Suncor owns a 58.74 percent interest in the Syncrude operation.  One of Syncrude's partners has projected that production could ramp up by 71 percent, from 350,000 BOPD to 600,000 BOPD by 2020, however, ongoing production problems have led partners to decide to increase production through increased reliability.

Here is a graph showing the ramping up of production by Syncrude's Mildred Lake operations since 1978:

Here is a graph showing the dramatic ramping up of production by Suncor since 1967:

Now, let's move to the northern operations.  Here is a screen capture from Google Earth showing the mining operations at CNRL's Horizon, Imperial Oil's Kearl, Shell's Muskeg North and Jackpine and Syncrude's Aurora North:

In 2012, CNRL produced 31.8 million barrels of synthetic crude, Syncrude produced 67.3 million barrels from Aurora North, Shell produced 46.9 million barrels from Muskeg North and an additional 35.5 million from Jackpine.  Imperial's Kearl project began production in April 2013 and is expected to produce around 110,000 BOPD of synthetic crude per day by late 2015, increasing to 345,000 BOPD by 2020 which works out to over 100 million barrels annually over 300 annual operating days.

Here is a graph showing how CNRL's production has looked since mining and upgrading began in 2009:

Note that CNRL has approvals for Phases 2A, 2B and 3 which will increase production by 137,000 BOPD from its current level of 110,000 BOPD.  Here is a closeup of what the CNRL mine site looks like after just five years of operation:

Note the already massive size of the settling pond.  For scale, the road coming in from the south side of the photo is a two lane highway.  This shows us how quickly the scale of mining operations can ramp up, a situation that will get even worse as CNRL builds Phases 2A, 2B and 3. 

Here is a graph showing the production history for Syncrude's Aurora North mine which began operation in 2001:

Here is a screen capture from Google Earth showing the size of the Aurora North mine, noting the two lane highway entering the mine from the lower left corner of the map for scale:

Here is a graph showing the production history for Shell's Muskeg North mine which began production in 2002:

Here is a graph showing the production history for Shell's Jackpine mine which began production in 2010:

Note that both Shell mines have been given approvals to expand production.

Four additional mines have already received approval; Syncrude's Aurora South, Total's North Joslyn (100,00 BOPD),  Suncor's Fort Hills (180,000 BOPD) and Shell Canada's Jackpine Expansion (100,000 BOPD).

Now for the damage and the key point of this posting.  Here is an excerpt from the Petropolis video which provides viewers with startling aerial views of a portion of Canada's oil sands mining operation:

That most certainly is not the "squirrel running up a tree", pastoral image that the oil industry likes to promote, is it?

As my regular readers know, I have 25 years of experience in Canada's oil industry as a geoscientist in conventional exploration.  I know that some of my actions led to environmental issues, both over the short- and long-term.  That said, when I watched the full version of Petropolis, the first thought that went through my mind was "post-apocalyptic wonderland".  I had no idea of the scale of the environmental damage done and how little had actually been accomplished to reclaim the mined areas and the tailings ponds and how much work would be required to make even a small dent in the ecological nightmare created by oil sands mining. 

In the interest of balance, here is the oil industry perspective provided by Suncor:

In 2010, Suncor claimed to be the first oil sands company to complete surface reclamation of a tailings pond, covering an area of 220 hectares or 543 acres.  Incidentally, the tailings pond was first used in 1967 and was in use for nearly 40 years.  While that is somewhat admirable, according to the Pembina Institute, in 2010, tailings ponds alone occupied 176 square kilometres or 17,600 hectares and is expected to grow to 250 square kilometres or 25,000 hectares by 2020.  Note that this does not include the size of the mined areas; in January 2013, the current area of boreal forest disturbed by oil sands mining operations was 715 square kilometres or 71500 hectares, the same size as the urbanized area of the entire City of Calgary or the entirety of New York City including all five boroughs.  In 2020, it is expected that the size of the area mined for oil sands will increase by an average of 18.6 hectares or the size of 34.5 football fields daily.

Post-apocalyptic wonderland indeed.

Keystone XL and Its Impact on the Economics of Canada's Oil Sands

Updated November 2014

An analysis of the economics of Canada's oil sands by Carbon Tracker Initiative examines how Keystone XL (KXL) will impact the economics of Canada's oil sands.  Canada's oil sands producers have long regarded KXL (or its alternative, the Northern Gateway Pipeline) as the panacea to the problem with high price differentials, currently in the 40 percent range between oil sands-sourced oil and conventional oil (West Texas Intermediate).

As background, Canada's oil sands producers have rather ambitious expansion plans.  From a production level of 1.8 million BOPD in 2012, production from oil sands is expected to rise to 2.3 million BOPD in 2014, 4.5 million BOPD in 2020 and 5.2 million BOPD in 2025.  Here is a graph showing the ramping up of production from 2012 to 2030:

One of the biggest problems facing Canada's oil sands producers is the infrastructure bottleneck that prevents oil from flowing to the United States Gulf Coast.  This is creating local gluts of oil, pushing prices for Western Canadian Select (WCS) (in red) well below the price for the benchmark Maya crude (in blue) as shown on this chart:

Maya, a heavy crude sourced in Mexico, similar in quality to WCS, however, it is not land-locked and is available to international markets in the United States Gulf Coast.  For 2013, the average WCS price was discounted by $24.41 per barrel when compared to Maya.  In November 2014, WCS was discounted at over $42 per barrel when compared to West Texas Intermediate, the North American benchmark crude.

The proposed KXL pipeline will link Alberta with the United States Gulf Coast, allowing oil companies to export an additional 830,000 BOPD of which 730,000 BOPD would be available for oil sands production and 100,000 BOPD would be available for tight oil plays in the Williston Basin (i.e. the Bakken).  The KXL pipeline would provide:

1.) A direct link to the Gulf Coast which would provide oil sands producers a price improvement (a reduction in the differential) since the oil sands oil (Western Canadian Select or WCS) is closer in quality to Mexican Maya which trades closer to the price of West Texas Intermediate (WTI).  As I noted above, Mexican Maya is still more valuable than WCS.

2.) The pipeline will relieve the pressure on existing export routes, allowing prices on WCS to rise in the Midwest.

Now that we have some background information, let's look at CTI's analysis.  As we know, the producing costs for much of Canada's oil sands are at the upper end of the upper quartile of the world's oil production cost curve.  In-situ or steam-assisted-gravity-drainage (SAGD) methods are the least costly, followed by non-upgraded mining production and projects with integrated mining operations and upgraders being the most expensive (i.e. Syncrude/Suncor).  Data from several analysts suggests that the break-even oil price required to make an oil sands project economic range from $60 to $100 per barrel with SAGD projects having a break-even price of $65 to $85 per barrel.  Here is a graphic showing the cost curves for some of the key new oil projects around the world with Canada's heavy oil sands projects in red:

As I noted above, the cost to produce a barrel of heavy Canadian oil ranges from about $52 per barrel to about $93 per barrel, depending on the project.  This is particularly pertinent given that WTI is now trading at around $80 per barrel.

Here is a chart showing the outcome at a price of $69 per barrel for WCS and a price of $89 per barrel for Mexican Maya, both in 2015, assuming a break-even price of $65 per barrel assuming a 10 percent discount rate:

Please note that profit/loss is measured after producer netback post-transportation less the break-even price of $65 per barrel.  The break-even price is the price per barrel required to cover all costs and provide the oil company involved with the rate of return (in this case, 10 percent) that it requires to proceed with a project.  It is highly likely that this break-even price will rise over time; it already appears that the break-even price for some projects may be in excess of $80 per barrel.

Without KXL, each barrel of WCS produced loses $18.10.  With KXL, profit rises to $5.50 per barrel.  With an incremental carbon offset cost of $2.00 per barrel, producers will see a net of $3.50 per barrel, a rather skinny profit margin.  Using a $65 per barrel initial cost and assuming that there are minimal carbon offset costs, KXL can shift projects from being unprofitable to being marginally profitable provided that refiners on the Gulf Coast are willing to pay the same price for WCS as they do for heavy Mexican Maya crude.

There are risks associated with this scenario:

1.) The demand for Canadian crude could drop as United States oil production rises (i.e. the Bakken and Eagle Ford among others) and more energy efficient vehicles reduce demand.  United States imports of crude oil and products have already dropped from 12 million BOPD in 2007 to 9.3 million barrels in mid-2014 as shown on this graph:

2.) Competitive pressures from imports of WCS could depress the price of Mexican Maya as PEMEX (Mexico's state oil company) seeks to maintain its market share by lowering prices.

3.) KXL could create a production cost inflation as development of new oil sands projects creates additional shortages of materials and labour.  If the cost of production were to rise by as little as 10 percent, this would push profits down by $6.50 per barrel in the analysis noted above.

4.) Highly volatile oil pricing could easily affect profitability.

5.) An increase in the desired rate of return will negatively impact the break-even point.  The return on projects demanded by oil companies will rise in lockstep with interest rates.

To summarize, if investors automatically assume that the green lighting of the Keystone XL pipeline will mean huge returns to shareholders, perhaps they should think twice.  Unless it appears that the world's oil markets will sustain a price scenario similar to what was seen through most of 2013 and early 2014 over the long-term, the economics of expanding Canada's oil sands industry looks like it could well be marginal at best.