Don’t worry – we’re not about to take you back to calculus class and the differential equations that would probably still give you nightmares if ever they crossed your mind. The differentials we care about right now don’t involve any Greek letters or mathematical symbols. In fact, they involve only one symbol: a dollar sign.
We’re talking about oil price differentials, which means the different prices paid for crude oil in different parts of the world. People often talk about “the price of oil” as though there is just one price, when really there are dozens of crude blends that each has a different valuation. Sure, some blends are much more prevalent and therefore important than others. Still, there is no single price of oil, and the differentials between various prices can be very important for the investor trying to gain an edge.
The Libyan uprising pushed the price of Brent North Sea crude up a year ago, but the benchmark North American oil price, West Texas Intermediate (WTI), did not follow suit – the loss of Libyan production was not significant in North America. More significant was a surge in domestic oil production that was having the opposite effect, pushing WTI prices down. These contrasting forces set the stage for a record differential between these two usually close prices, one that persists today:
(Click on image to enlarge)
This differential did attract a fair bit of attention from the mainstream media, which generally attributed the difference to upside pressure on Brent stemming from the Arab Spring. At Casey, we think the more important force at work is the downside pressure acting on WTI prices. If you think the WTI-Brent differential is big, you ain’t seen nothing yet.
Another major US crude grade is Light Louisiana Sweet (LLS), which as the name implies is a high-quality crude that has always earned a good price. These days LLS is trading for almost as much as Brent, with a price near US$117 per barrel. Oil produced from the tight shales of the Bakken formation is also pretty darn good oil, but it is worth only US$70.74. West Canada Select, the heavy oil produced from Canada’s oil sands, is worth even less, its current spot price struggling to stay above US$65 per barrel.
Price (US$ per barrel)
Brent North Sea
West Texas Intermediate (Cushing)
Light Louisiana Sweet
West Canada Select
Edmonton Syncrude Sweet
The causes almost all relate to infrastructure, or more specifically to a lack of pipeline infrastructure. We delve into that situation in the main article below.
If you want to skip right to the bottom line, it is this: location matters. Bakken producers are getting hammered on pricing because they struggle to get their oil to the nearest refinery and storage hub – in Cushing, Oklahoma. Then, in a cruel feedback cycle, once the oil reaches Cushing it actually pushes its own value down by adding to a supply glut – there isn’t enough refinery capacity in Cushing to process rising output from the Bakken and the Canadian oil sands, and there are only a few small pipes available to ease the glut by moving oil from Cushing to the big, sophisticated refineries on the Gulf Coast.
When investing in any company, it is vital to understand its cash flow. For oil and gas producers, cash flow can dry up all too quickly if pricing differentials move the wrong way. As an investor you have to recognize that the “price of oil” quoted on the morning news is likely very different from the price ABC Oil is getting for its output, and the differential could well mean that ABC is a value trap rather than a prime pick.
That is why differentials matter. Think about it: a Bakken producer garnering just $70 for each barrel of oil has to produce 70% more oil than a Louisiana producer just to bring in the same amount of gross revenue. It’s pretty hard to produce that much more oil without having proportionately greater costs as well…and you can see where this math goes. Better pricing equals better cash flow, so do your differentials homework before jumping into any oil investment.
It takes a lot of time to conduct this due diligence, but (thankfully) you don’t have to do it yourself. Instead, you can entrust this vital work to our team of energy experts via the Casey Energy Report. In the upcoming CER March issue, we reveal a matter of critical importance to energy investors – the exploding oil production of the Bakken region. Read on for more information.
And now, let’s delve a little deeper into the whats, whys, and hows of today’s dramatic pricing differentials.
Chief Energy Investment Strategist
By Marin Katusa, Chief Energy Investment Strategist
Think $100-a-barrel oil is too darn expensive? Want to buy a barrel of oil for $65 instead? Well, you can. In fact, it’s just north of the border.
The price for a barrel of Western Canada Select – the benchmark blend for crude produced from the Canadian oil sands – fell below $63 last week. It then recovered slightly but even now remains at a 33% discount to West Texas Intermediate, the North American benchmark that is currently trading at almost $100 a barrel, and a 44% discount to Brent North Sea crude, the European benchmark that is sitting near $118 a barrel.
Why is Canadian crude so cheap, you ask? For two reasons: one that is permanent and the other, we hope, transient. The permanent reason is that heavy crudes are harder to refine than light crudes, so refiners are able to buy heavy blends at a discount in recognition of the higher costs incurred in transforming them into finished petroleum products. That discount has run at about 20% for the last few years. The other force currently at play, pushing the discount to almost double its usual level, is a lack of infrastructure.
The situation in its entirety involves many factors, ranging from North Dakota’s shale-oil boom to the billions spent on refinery upgrades in Texas. The fallout from a failure to fix the problem is not pretty. New oil-sands projects are uneconomic at $65 a barrel, but the oil sands represent one of America’s only friendly, increasing sources of crude oil – without continued ramp-up in Canadian supplies, the US will remain locked into dependency on suppliers like Nigeria, Iraq, Angola, Algeria, and Venezuela.
The solution, however, is pretty straightforward: build more pipelines. But build them quickly, because Canada will not wait forever for a commitment from the US. Another buyer is waiting in the wings, armed with billions of dollars and a mandate to lock in energy supplies to feed its huge, oil-hungry population.
The problem is very basic: demand is exceeding supply. But that balance doesn’t refer to oil – it describes North America’s pipeline capacity. There are already more than a million kilometers of oil and gas pipelines crisscrossing the United States alone, and they count among the safest in the world. But the geographic distribution of oil production on the continent is shifting, creating the need for specific new pipelines to connect booming oil hot spots with refineries thirsty for crude.
The top three oil states in the US have long been Texas, Alaska, and California. Texas has produced a roughly a million barrels of oil per day (bpd) for a decade (it produced more before that); Alaska used to pump a million bpd but now kicks out about 600,000; and California’s production has dwindled from 900,000 bpd ten years ago to 550,000 bpd today.However, while production in the top three states stagnates or dwindles, there’s a new player on the team.
That player is North Dakota, where oil production increased 42% during 2011 to surpass half a million barrels a day near the end of the year. Put another way, oil production in the state has increased anywhere from 8,000 to 40,000 barrels a day every month since June. Over the last two years, output has doubled.
(Click on image to enlarge)
North Dakota’s oil boom is great news for the US. Half a million barrels a day is equivalent to America’s imports from Algeria and is more than top-fifteen suppliers Iraq, Angola, Ecuador, and Brazil. It is almost as much oil as the US currently imports from Russia. The point of these comparisons is that North Dakota’s oil boom is enabling the US to move away from some of its riskier, less-reliable suppliers in favor of good old domestic production.
The only downside is that North Dakota’s oil is now in direct competition with crude from the Canadian oil sands for pipeline space. Crude oil is not particularly useful until it is refined, and the center of North America’s refining universe is the Gulf Coast. The 45 refineries along the Coast process more than eight million barrels of oil per day, accounting for almost half of America’s refining capacity.
Those refineries have lots of capacity available to process all this new, North American crude. The issue is getting it there.
As North Dakota’s oil production climbed, so did production in western Canada, growing by 7% last year. Both markets now feed into the refineries and oil storage tanks in the US Midwest, a processing district centered on the city of Cushing, Oklahoma. Pipelines running from Canada and North Dakota into Cushing are already jammed, so much so that many producers are using rail to move their product to market. Moving oil by rail is always significantly more expensive than moving it through a pipeline, so the fact that producers are relying on rail is a sure sign that pipeline capacity is maxed out.
The problem doesn’t end with getting the oil to Oklahoma. There are some refineries in the Cushing area – in fact, there was once so much oil production in Texas that, combined with imports from Mexico and South America, Gulf Coast refineries were overwhelmed. To help out, Cushing-area refineries used to take some of the excess. Now those few Cushing refineries have nowhere near the capacity to deal with current output from Canada and North Dakota, so instead of flowing north the oil needs to flow south.
The southern leg of Keystone XL would alleviate a lot of this pressure. Running from Cushing to Houston and Port Arthur, Texas, it would move roughly half a million barrels of oil a day from the overflowing storage tanks at Cushing to refineries. We’re hopeful that Keystone XL in its entirety will receive approval once the presidential election is over; if it looks like it is going to take longer to re-route the contentious Nebraska portion, TransCanada has mentioned trying to fast-track the southern leg to start alleviating the Cushing glut as soon as possible.
Thankfully, there is also help coming in the shorter term. Enbridge (T.ENB, NYSE.ENB) and its partner Enterprise Products Partners (NYSE.EPD) are working to reverse the flow of crude oil in the Seaway pipeline, which connects Cushing with Freeport, Texas. It was one of the lines that used to move oil north. Since all they need to do is build a few new pump stations, the partners expect to have the pipe moving 150,000 barrels per day southward by mid-2012, rising to 400,000 bpd by 2013.
Irony can be painful… and right now Gulf Coast refiners know just how painful.
In the last decade, US refiners invested billions into upgrading their facilities to accommodate heavier, sourer crude oils. There were two drivers behind the shift. One is that the world is slowly but surely running out of light, sweet oil deposits, which means production is generally shifting to heavier, sourer crudes. The other is that heavy, sour crudes are cheaper than light, sweet ones, so once their facilities are upgraded to handle heavy oil, refiners can save money on their crude purchases.
The catch is that refineries can only process specific crude grades. Once a refinery has been upgraded to process heavy oil, the facility can no longer work light crudes; it has to be fed with heavy oil. As such, all the sophisticated refineries on the Gulf Coast need heavy oil, not only to save money but because it’s the only kind of oil they can run.
The cruel irony now is that they can’t get their hands on that cheap, heavy crude. Canadian crude is exactly the kind of oil these sophisticated refineries need but it’s all piling up in Cushing, 700 km to the north. Without a way to pump it down south, Gulf Coast refiners with sophisticated facilities are instead being forced to pay a premium for heavy oil from Venezuela.
Only a few years after spending billions of dollars on upgrades in preparation for an influx of heavy oil, these proactive refiners are now being forced to pay extra for the heavy oil they were supposed to be able to buy at a discount. For them, the Seaway reversal and the southern leg of Keystone XL can’t come soon enough.
As nice as $65-per-barrel oil sounds, that is actually too cheap. With each passing year the average cost to produce a barrel of crude oil creeps upward, as the easy deposits of light, sweet oil start to run out and producers are forced to use more complicated, expensive means to access new oil: They have to go deeper, use fracturing technology, work underneath kilometers of water, or work in countries where fiscal and social risks run high.
The oil sands are a prime example. If the price for Western Canadian Select crude oil remains in the $60 to $70 range for very long, new projects will start getting cancelled. Producing a barrel of oil-sands crude from an existing operation – one where the capital costs have already been repaid – costs between $36 and $45 a barrel. For established operations, therefore, $65 oil is just manageable.
For new projects, however, the bar is higher. Every cost involved in building and manning an oil-sands operation has increased notably over the last decade, from the cost of tires to the costs of employee health-insurance programs. A new oil sands operation, even an in-situ project where the size and therefore cost can be ramped up gradually, needs a crude price of at least $80 a barrel before the project’s economics turn from red to black.
If new pipelines running south fail to materialize and the lack of capacity keeps Western Canadian Select below $75 a barrel, oil-sands development will slow. Environmentalists might cheer at that notion, but without Canadian supplies the US will be forced to continue relying on places like Nigeria for crude oil. If pictures of oil-sands operations make your green heart tremble, photos of the huge oil spills and daily natural gas flare-offs in Nigeria might stop it dead in its tracks. Oil extraction is never pretty, but at least environmental regulations in North America limit the damage substantially. Nigerians are not so lucky – and by buying Nigerian oil, the US supports that country’s dirty oil industry.
The other fallout of a failure to build up North America’s pipeline capacity is that China will benefit. Canada knows it has a very valuable resource in its oil sands; and if pipelines heading south can’t happen, then the US’s northern neighbor will figure out a way to get its oil to the Pacific, an effort that is already being encouraged and funded by energy-hungry China. Pipeline capacity from the oil sands to the west coast is currently very limited, but there are several proposed lines that would boost westbound volumes dramatically, if approved. That is a big “if,” because Native groups across British Columbia are opposed to the current proposals. Still, oil-sands crude needs new outlets and, with enough time and negotiation, it seems likely that at least one of those outlets will be on the west coast.
China would probably sign on to building a pipeline to the coast tomorrow. The Canadian prime minister just completed a weeklong trip to China wherein one of the main foci was energy; the CEO of pipeline major Enbridge (T.ENB) was part of Prime Minister Harper’s entourage. Chinese energy companies have invested no less than C$10 billion in Canada’s oil and gas sector in expectation of a growing energy connection between the countries.
If the United States wants to build a more secure energy future, Americans (and Canadians) need to let the oil flow. By all means, avoid the Ogallala aquifer and do everything possible to protect the sensitive Sandhills region. But build a couple pipelines, and build them now.
Sanctions on Iran are already hitting global oil flows, even though the EU ban on imports from the Islamic Republic does not come into effect until July, according to the International Energy Agency. The agency, which acts as global adviser on energy policy, estimates that up to 1 million of Iran’s 2.6 million barrels per day of oil exports may be replaced by alternative supplies once the sanctions are fully implemented. European and Asian customers are already lining up alternative sources of supply.
For the sixth consecutive month the International Energy Agency has cut its 2012 oil growth demand forecast. Citing a weak global economy, the Agency cut its oil demand growth forecast by 250,000 barrels per day (bpd), to sit at just 800,000 bpd. The Organization of Petroleum Exporting Countries (OPEC) made a similar cut to its forecast, predicting that demand will rise by only 940,000 bpd in 2012. Nevertheless, oil supplies from OPEC rose in January to their highest volumes since October because of a steady ramp-up in Libyan production to average 30.9 million bpd.
Nuclear Reactor Approved in US for First Time Since 1978 (Scientific American)
The US Nuclear Regulatory Commission voted to allow construction of two new nuclear reactors near Augusta, Georgia, but what were initially lauded as the first reactors of a nuclear renaissance when proposed are now more likely to be the exception that proves the rule of no new nuclear construction in the US. The only reactors likely to be built in the US over the next ten years are this twin set of reactors in Georgia, another pair in South Carolina, and the completion of an old reactor in Tennessee. The problem: Electricity demand in the US is not growing and natural gas, which can be burned to generate power, is cheap. Nuclear power plants, on the other hand, are not: each new reactor costs an average of $14 billion.
BHP Billiton just placed a $20-billion bet on US natural gas. Near the start of 2011 the company, under the guidance of CEO Marius Kloppers, spent $4.75 billion to buy of Chesapeake Energy’s acreage in the Fayetteville shale; a few months later he bet again, paying $15 billion for Petrohawk Energy and its accumulation of prime shale fields in Louisiana and Texas. BHP, a company with zero prior experience drilling for shale gas, suddenly became one of the 15 largest natural gas producers in the United States. The $20 billion spent on acquiring the lands is only the start: BHP expects to spend ten years and $50 billion more developing these shale assets. At today’s natural gas prices, depressed by the domestic supply glut, the projects aren’t even economic. But BHP’s executives believe that demand will follow supply in time, and by then their company will be perfectly positioned.
Speaking at the 33rd anniversary of the Islamic Revolution that toppled the US-backed Shah in Iran, President Mahmoud Ahmadinejad said on Saturday that his country is primed to unveil several completed nuclear projects. The official government website added that the progress will underline Iran’s scientific adherence to “nuclear power for all and nuclear weapons for none.”